Edgar Filing: WHITING PETROLEUM CORP

Form 424(b)(3)

Filed Pursuant to Rule 424(b)(3)

Registration No. 333-115957

PROSPECTUS

LOGO

Whiting Petroleum Corporation

Offer to Exchange

All Outstanding

7 1/4% Senior Subordinated Notes due 2012

$150,000,000 Aggregate Principal Amount

for

New 7 1/4% Senior Subordinated Notes due 2012

$150,000,000 Aggregate Principal Amount

•

We are offering to exchange new registered 7 1/4% senior subordinated notes due 2012 for all of our outstanding unregistered 7 1/4% senior subordinated notes due 2012.

•

The exchange offer expires at 5:00 p.m., New York City time, on July 9, 2004, unless we extend it.

•

The terms of the new notes are substantially identical to those of the old notes, except that the new notes will not have securities law transfer restrictions and registration rights relating to the old notes and the new notes will not provide for the payment of additional interest under circumstances relating to the timing of the exchange offer.

•

The new notes will be unconditionally guaranteed, jointly and severally, by certain of our subsidiaries on a senior subordinated basis.

•

All outstanding old notes that are validly tendered and not validly withdrawn will be exchanged.

•

You may withdraw your tender of old notes any time before the exchange offer expires.

•

We will not receive any proceeds from the exchange offer.

•

No established trading market for the new notes currently exists. The new notes will not be listed on any securities exchange or included in any automated quotation system.

•

The exchange of notes will not be a taxable event for U.S. federal income tax purposes.

See “ Risk Factors” beginning on page 11 for a discussion of risk factors that you should consider before deciding to exchange your old notes for new notes.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is June 9, 2004.

TABLE OF CONTENTS


		Page
Prospectus Summary		1
Risk Factors		11
Forward–Looking Statements		22
Use of Proceeds		22
Capitalization		23
The Exchange Offer		24
Selected Historical Financial Information		32
Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
Business and Properties		49
Management		62
Principal Holders of Common Stock		65
Description of Other Indebtedness		66
Description of the New Notes		67
United States Federal Income Tax Considerations		108
Plan of Distribution		109
Legal Matters		110
Independent Auditors		110
Independent Oil and Gas Consultants		110
Where You Can Find More Information		110
Index to Financial Statements		F-1
Glossary of Oil and Natural Gas Terms		A-1

Unless the context otherwise requires, references in this prospectus to “Whiting,” “we,” “us,” “our” or “ours” 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 prospectus incorporates important business and financial information about us that is not included in or delivered with this prospectus. We will provide you without charge upon your request, a copy of any documents that we incorporate by reference, other than exhibits to those documents that are not specifically incorporated by reference into those documents. You may request a copy of a document by writing to Patricia J. Miller, Vice President—Human Resources and Corporate Secretary, Whiting Petroleum Corporation, 1700 Broadway, Suite 2300, Denver, Colorado 80290-2300, or by calling Ms. Miller at (303) 837-1661. To ensure timely delivery, you must request the information no later than five business days before the completion of the exchange offer. Therefore, you must make any request on or before July 1, 2004.

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PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. You should read this entire prospectus carefully, including “Risk Factors” and our financial statements and the notes to those financial statements included elsewhere in this prospectus. We have provided definitions for the oil and natural gas terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” included in this prospectus. The reserve information and other related operating statistics contained in this prospectus are as of January 1, 2004 unless otherwise indicated.

About Our Company

We are engaged in oil and natural gas exploitation, acquisition, exploration and production activities primarily in the Gulf Coast/Permian Basin, Rocky Mountains, Michigan and Mid-Continent regions of the United States. Our focus is on pursuing growth projects that we believe will generate attractive rates of return and maintaining a balanced portfolio of lower risk, long-lived oil and natural gas properties that provide stable cash flows.

Since our inception in 1980, we have built a strong asset base and achieved steady growth through both property acquisitions and exploitation activities. As of January 1, 2004, our estimated proved reserves had a pre-tax PV10% value of approximately $784.6 million, approximately 85% of which came from properties located in three states: Texas, North Dakota and Michigan. We spent approximately $52.0 million on capital projects during 2003, including $38.8 million for the drilling of 72 gross (24.8 net) wells (64 successful completions and eight uneconomic wells). We have budgeted approximately $68.0 million for capital expenditures in 2004, including $33.0 million for the development of proved reserves and $35.0 million for the development of currently unproved reserves. Although we have no specific budget for acquisitions, we will also continue to seek property acquisition opportunities that complement our existing core properties. We believe that our exploitation and acquisition expertise and our exploration inventory, together with our operating experience and efficient cost structure, provide us with the potential to continue our growth.

We have a balanced portfolio of oil and natural gas reserves, with approximately 53% of our proved reserves consisting of natural gas and approximately 47% consisting of oil. Our properties generally have long reserve lives and reasonably stable and predictable well production characteristics with a ratio of proved reserves to trailing 12 month production ending December 31, 2003 of approximately 11.8 years. Approximately 75% of our proved reserves are classified as proved developed and approximately 25% are classified as proved undeveloped.

The following table summarizes our total net proved reserves and pre-tax PV10% value within our four core areas as of January 1, 2004, as well as our December 2003 average daily production.


	Proved Reserves			Pre-Tax PV 10% Value (In thousands)		December 2003 Average Daily Production
Core Area	Oil (MMbbl)	Natural Gas (Bcf)	Total (Bcfe)	Pre-Tax PV 10% Value (In thousands)		MMcfe	% Natural Gas
Gulf Coast/Permian Basin	5.5	89.4	122.5	$	266,745	40.0	76	%
Rocky Mountains	26.5	17.6	176.5		261,071	32.3	11	%
Michigan	1.1	107.2	114.1		214,407	21.3	92	%
Mid-Continent	1.5	16.8	25.7		42,400	8.2	73	%

Total	34.6	231.0	438.8	$	784,623	101.8	59	%

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Business Strategy

Our goal is to increase stockholder value by investing in oil and gas projects with attractive rates of return on capital employed. We plan to achieve this goal by exploiting and developing our existing oil and natural gas properties and pursuing acquisitions of additional properties. Specifically, we have focused, and plan to continue to focus, on the following:

Developing and Exploiting Existing Properties. We believe that there is significant value to be created by drilling the numerous identified undeveloped opportunities on our properties. We own interests in a total of 517,000 gross (206,000 net) developed acres. In addition, as of December 31, 2003, we owned interests in approximately 386,000 gross (188,000 net) undeveloped acres that contain many exploitation opportunities. During the three years ended December 31, 2003, we invested $94 million to participate in the drilling of 169 gross (60.6 net) wells. The majority of these wells were developmental wells, and 85.2% were successful completions. As of January 1, 2004, we had identified a total of 171 proved undeveloped drilling locations on our properties. We drilled or participated in the drilling of 72 gross (24.8 net) wells during the year ended December 31, 2003. We plan to invest $68 million on the further development of our properties in 2004.

Pursuing Profitable Acquisitions. We have pursued and intend to continue to pursue acquisitions of properties that we believe to have exploitation and development potential comparable to our existing inventory of drilling locations. We have developed and refined an acquisition program designed to increase reserves and complement our existing core properties. We have an experienced team of management and engineering and geoscience professionals who identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties.

Focusing on High Return Operated and Non-Operated Properties. 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 they meet our return criteria and further our growth strategy.

Controlling Costs through Efficient Operation of Existing Properties. We operate approximately 60% of the pre-tax PV10% value of our total proved reserves and approximately 82% of the pre-tax PV10% value of our proved undeveloped reserves, which we believe enables us to better manage expenses, capital allocation and the decision-making processes related to our exploitation and exploration activities. For the year ended December 31, 2003, our lease operating expense per Mcfe averaged $1.16 and general and administrative costs averaged $0.34 per Mcfe produced, net of reimbursements.

Competitive Strengths

We believe that our key competitive strengths lie in our diversified asset base, our experienced management team and our commitment to efficient utilization of new technologies.

Diversified Asset Base. We have interests in 5,006 wells in 16 states across our four core geographical areas of the United States. This property base, as well as our continuing business strategy of acquiring and developing properties in our core operating areas, presents us with a large number of opportunities for successful development and exploitation and additional acquisitions.

Experienced Management Team. Our management team averages 26 years of experience in the oil and natural gas industry. Our personnel have extensive experience in each of our core geographical areas and in all of our operational disciplines. In addition, each of our acquisition professionals has at least 20 years of experience in the evaluation, acquisition and operational assimilation of oil and natural gas properties.

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Commitment to Technology. In each of our core operating areas, we have accumulated detailed geologic and geophysical knowledge and have developed significant technical and operational expertise. In recent years, we have developed considerable expertise in conventional and 3-D seismic imaging and interpretation. Our technical team has access to approximately 575 square miles of 3-D seismic data, which we have assembled primarily over the past five years. A team with access to state-of-the-art geophysical/geological computer applications and hardware analyzes this information. Computer applications, such as the WellView^® software system, enable us to quickly generate reports and schematics on our wells. In addition, our information systems enable us to update our production databases through daily uploads from hand-held computers in the field. This technology and expertise has greatly aided our pursuit of attractive development projects.

Acquisition of Equity Oil Company

On February 2, 2004, we announced that we had entered into a definitive merger agreement to acquire Equity Oil Company in a transaction valued at approximately $76.2 million based on the closing sale price of our common stock on the New York Stock Exchange on January 30, 2004, the last trading day immediately prior to the public announcement of the transaction, including the assumption of debt outstanding under Equity’s credit facility, which was approximately $29.0 million of as of March 31, 2004. Due to the fixed exchange ratio discussed below and the increase in the closing price per share of our common stock on the New York Stock Exchange from $19.24 on January 30, 2004 to $24.12 on June 7, 2004, the transaction would be valued at $90.2 million as of June 7, 2004, including the assumption of debt.

Equity Oil Company is an independent energy company that explores for, exploits and produces oil and natural gas with operations 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). For the three months ended March 31, 2004, Equity reported income from continuing operations of $0.4 million, net cash provided by operating activities of $1.9 million and production of 140,000 barrels of oil and 605 MMcf of natural gas. As of December 31, 2003, based on the reserve report prepared by Ryder Scott Company, L.P., independent petroleum engineers, Equity had 87.7 Bcfe of proved oil and natural gas reserves and a net present value of proved oil and natural gas reserves (using year-end prices and costs held constant and discounted at 10%) of $94.0 million.

The merger agreement provides for a stock-for-stock merger pursuant to which Equity shareholders will receive a fixed exchange ratio of 0.185 shares of our common stock for each share of Equity common stock that they own. The merger is subject to the approval of shareholders owning two-thirds of the outstanding Equity shares and other customary closing conditions. Two directors of Equity, including Equity’s President and Chief Executive Officer, have agreed with us to vote all of their Equity shares in favor of the merger and have given us an option to acquire their shares under certain circumstances. Together, these directors own approximately 16.6% of the outstanding Equity common stock. Equity intends to call a special meeting of its shareholders during the second quarter of 2004 to consider and vote on the merger. We expect to complete the merger as soon as practicable following approval by Equity’s shareholders.

Corporate Information

Whiting Petroleum Corporation was incorporated in Delaware on July 18, 2003 for the sole purpose of becoming a holding company of Whiting Oil and Gas Corporation in connection with our initial public offering. Whiting Oil and Gas Corporation was incorporated in Delaware in 1983. Prior to our initial public offering in November 2003, we were a wholly-owned subsidiary of Alliant Energy Corporation, an energy services provider engaged primarily in regulated utility operations in the Midwest, with other non-regulated domestic and international operations.

Our principal executive offices are located at 1700 Broadway, Suite 2300, Denver, Colorado, 80290-2300, and our telephone number is (303) 837-1661.

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The Exchange Offer


Old Notes		We sold $150,000,000 aggregate principal amount of our 7¼% Senior Subordinated Notes due 2012, which are unconditionally guaranteed, jointly and severally, by some of our subsidiaries on a senior subordinated basis, to the initial purchasers on May 11, 2004. In this prospectus, we refer to those notes as the old notes. The initial purchasers resold the old notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933 and to non-U.S. persons in transactions outside the United States pursuant to Regulation S under the Securities Act of 1933.

Registration Rights Agreement		When we sold the old notes, we entered into a registration rights agreement with the initial purchasers in which we agreed, among other things, to provide you and all other holders of the old notes the opportunity to exchange your unregistered old notes for a new series of substantially identical notes that we have registered under the Securities Act. The exchange offer is being made for that purpose.

New Notes		We are offering to exchange the old notes for 7¼% Senior Subordinated Notes due 2012 that we have registered under the Securities Act, which are unconditionally guaranteed, jointly and severally, by some of our subsidiaries on a senior subordinated basis. In this prospectus, we refer to those registered notes as the new notes. The terms of the new notes and the old notes are substantially identical except:

		• the new notes will be issued in a transaction that will have been registered under the Securities Act;

		• the new notes will not contain securities law restrictions on transfer; and

		• the new notes will not provide for the payment of additional interest under circumstances relating to the timing of the exchange offer.

The Exchange Offer		We are offering to exchange $1,000 principal amount of the new notes for each $1,000 principal amount of your old notes. As of the date of this prospectus, $150,000,000 aggregate principal amount of the old notes are outstanding. For procedures for tendering, see “The Exchange Offer — Procedures for Tendering Old Notes.”

Expiration Date		The exchange offer will expire at 5:00 p.m., New York City time, on July 9, 2004, unless we extend it.

Resales of New Notes		We believe that the new notes issued pursuant to the exchange offer in exchange for old notes may be offered for resale, resold and otherwise transferred by you without compliance with the registration and prospectus delivery provisions of the Securities Act if:

		• you are not our “affiliate” within the meaning of Rule 405 under the Securities Act;

		• you are acquiring the new notes in the ordinary course of your business; and

		• you have not engaged in, do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of the new notes.

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		If you are an affiliate of ours, or are engaging in or intend to engage in, or have any arrangement or understanding with any person to participate in, a distribution of the new notes, then:

		• you may not rely on the applicable interpretations of the staff of the SEC;

		• you will not be permitted to tender old notes in the exchange offer; and

		• you must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the old notes.

		Each participating broker-dealer that receives new notes for its own account under the exchange offer in exchange for old notes that were acquired by the broker-dealer as a result of market-making or other trading activity must acknowledge that it will deliver a prospectus in connection with any resale of the new notes. See “Plan of Distribution.”

		Any broker-dealer that acquired old notes from us may not rely on the applicable interpretations of the staff of the SEC and must comply with registration and prospectus delivery requirements of the Securities Act (including being named as a selling securityholder) in connection with any resales of the old notes or the new notes.

Acceptance of Old Notes and Delivery of New Notes		We will accept for exchange any and all old notes that are validly tendered in the exchange offer and not withdrawn before the offer expires. The new notes will be delivered promptly following the exchange offer.

Withdrawal Rights		You may withdraw your tender of old notes at any time before the exchange offer expires.

Conditions of the Exchange Offer		The exchange offer is subject to the following conditions, which we may waive:

		• the exchange offer, or the making of any exchange by a holder of old notes, will not violate any applicable law or interpretation by the staff of the SEC; and

		• no action may be pending or threatened in any court or before any governmental agency with respect to the exchange offer that may impair our ability to proceed with the exchange offer.

Consequences of Failure to Exchange		If you are eligible to participate in the exchange offer and you do not tender your old notes, then you will not have further exchange or registration rights and you will continue to hold old notes subject to restrictions on transfer.

Federal Income Tax Consequences		The exchange of old notes for new notes will not be taxable to a United States holder for federal income tax purposes. Consequently, you will not recognize any gain or loss upon receipt of the new notes. See “United States Federal Income Tax Considerations.”

Use of Proceeds		We will not receive any proceeds from the exchange offer.

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Accounting Treatment		We will not recognize any gain or loss on the exchange of notes. See “The Exchange Offer—Accounting Treatment.”

Exchange Agent		J.P. Morgan Trust Company, National Association, is the exchange agent. See “The Exchange Offer—Exchange Agent.”

The New Notes

The following is a brief summary of some of the terms of the new notes. For a more complete description of the terms of the new notes, see “Description of the New Notes” in this prospectus.



Issuer		Whiting Petroleum Corporation

Notes offered		$150,000,000 aggregate principal amount of 7 1/4% senior subordinated notes due 2012.

Maturity date		May 1, 2012.

Interest payment dates		May 1 and November 1, beginning November 1, 2004.

Ranking		The new notes will be unsecured senior subordinated obligations and will be subordinated to all of our senior debt. The new notes will rank equally with any senior subordinated debt we may incur in the future and will rank senior to any subordinated debt we may incur in the future. See “Description of Other Indebtedness” for a description of our indebtedness. As of March 31, 2004, after giving effect to the issuance of the old notes and the application of the net proceeds therefrom, we would have had total senior debt of approximately $3.1 million (excluding our guarantee of Whiting Oil and Gas Corporation’s credit agreement), no senior subordinated debt other than the notes and no debt subordinated to the notes, and our operating subsidiary, Whiting Oil and Gas Corporation, would have had senior debt of approximately $1.1 million consisting of borrowings under its credit agreement and no other debt. If our pending acquisition of Equity Oil Company is completed, Whiting Oil and Gas Corporation expects to incorporate into its credit agreement the senior debt outstanding under Equity’s credit facility, which was approximately $29.0 million as of March 31, 2004.

Optional redemption		We will have the option to redeem the new notes, in whole or in part, at any time on or after May 1, 2008, at the redemption prices described in this prospectus under the heading “Description of the New Notes—Optional Redemption,” together with any accrued and unpaid interest to the date of redemption.

Equity offering optional redemption		Before May 1, 2007, we may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the new notes with the net proceeds of a public or private equity offering at 107.25% of the principal amount of the new notes, plus any accrued and unpaid interest, if at least 65% of the aggregate principal amount of the new notes issued under the indenture remains outstanding after such redemption and

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		the redemption occurs within 120 days of the date of the closing of such equity offering.

Change of control		When a change of control event occurs, each holder of new notes may require us to repurchase all or a portion of its new notes at a price equal to 101% of the principal amount of such new notes, plus any accrued and unpaid interest.

Guarantees		The new notes will be unconditionally guaranteed, jointly and severally, by certain of our subsidiaries on a senior subordinated basis. All of our existing subsidiaries are restricted subsidiaries.

Certain Covenants		The indenture governing the new notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to:

		• pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our subordinated debt,

		• make investments,

		• incur additional indebtedness or issue preferred stock,

		• create certain liens,

		• sell assets,

		• enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us,

		• consolidate, merge or transfer all or substantially all of the assets of us and our restricted subsidiaries taken as a whole,

		• engage in transactions with affiliates,

		• create unrestricted subsidiaries, and

		• enter into sale and leaseback transactions.

		These covenants are subject to important exceptions and qualifications that are described under the heading “Description of the New Notes” in this prospectus.
Absence of a public market for the notes		The new notes are new securities and there is currently no established market for the new notes. We do not intend to apply for a listing of the new notes on any securities exchange or for the inclusion of the new notes on any automated dealer quotation system. Accordingly, we cannot assure you as to the development or liquidity of any market for the new notes.

Risk factors		See “Risk Factors” and the other information in this prospectus for a discussion of factors you should carefully consider before deciding to exchange your old notes for new notes.

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Summary Historical Financial Information

The following summary historical financial information for each of the years ended December 31, 2003, 2002 and 2001 has been derived from our audited consolidated financial statements and related notes. The summary historical financial information for the three months ended March 31, 2004 and 2003 has been derived from our unaudited consolidated financial statements and related notes. This information is only a summary and you should read it in conjunction with material contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our financial statements included elsewhere in this prospectus.


	Three Months Ended March 31,						Year Ended December 31,
	2004			2003			2003			2002			2001
	(dollars in millions)
Consolidated Income Statement Information:
Revenues:
Oil and gas sales	$	47.6		$	49.5		$	175.7		$	122.7		$	125.2
Gain (loss) on oil and gas hedging activities		(1.0	)		(6.7	)		(8.7	)		(3.2	)		2.3
Gain on sale of oil and gas properties		—			—			—			1.0			11.7
Interest income and other		0.1			—			0.3			—			0.2

Total revenues	$	46.7		$	42.8		$	167.3		$	120.5		$	139.4
Costs and expenses:
Lease operating	$	10.5		$	10.7		$	43.2		$	32.9		$	29.8
Production taxes		3.0			3.0			10.7			7.4			6.5
Depreciation, depletion and amortization ⁽¹⁾		10.7			10.6			41.2			43.6			26.9
Exploration		0.4			0.2			3.2			1.8			0.8
Phantom equity plan ⁽²⁾		—			—			10.9			—			—
General and administrative		4.0			3.2			12.8			12.0			10.9
Interest expense		2.3			3.2			9.2			10.9			10.2

Total costs and expenses	$	31.0		$	30.9		$	131.2		$	108.6		$	85.1

Income before income taxes and cumulative change	$	15.7		$	11.9		$	36.1		$	11.9		$	54.3
Income tax expense ⁽³⁾		6.1			4.5			13.9			4.2			13.1

Income from continuing operations		9.6			7.5			22.2			7.7			41.2
Cumulative change in accounting principle ⁽⁴⁾		—			(3.9	)		(3.9	)		—			—

Net income	$	9.6		$	3.6		$	18.3		$	7.7		$	41.2

Other Financial Information:
Net cash provided by operating activities	$	14.3		$	15.6		$	96.4		$	62.6		$	62.3
Capital expenditures ⁽⁵⁾	$	11.5		$	5.2		$	52.0		$	165.4		$	99.6
Ratio of earnings to fixed charges ⁽⁶⁾		7.62x			4.65x			4.85x			2.08x			6.10x

	As of March 31,						As of December 31,
	2004			2003			2003			2002			2001
Balance Sheet Information:
Cash and cash equivalents	$	16.4		$	15.6		$	53.6		$	4.8		$	1.0
Total assets	$	498.6		$	467.6		$	536.3		$	448.5		$	319.8
Total debt	$	148.1		$	185.0		$	188.0		$	265.5		$	163.6
Stockholders’ equity	$	271.3		$	208.3		$	259.6		$	122.8		$	111.5

⁽¹⁾

We reduced the amount of our abandonment liability estimate from approximately $13.0 million at December 31, 2000 to $4.0 million at December 31, 2001 as a result of receiving a revised and more detailed dismantlement plan from our dismantlement operator. This $9.0 million change in estimate reduced our depreciation, depletion and amortization expense in our 2001 financial statements as the expense for the abandonment liability had originally been recorded as a depreciation, depletion and amortization expense.

⁽²⁾

The completion of our initial public offering in November 2003 constituted a triggering event under our phantom equity plan, pursuant to which our employees received payments valued at $10.9 million in the form of shares of our common stock valued at approximately $6.5 million after withholding of shares for payroll and income taxes. As a result, in the fourth quarter of 2003, we recorded a one-time non-cash charge of $6.5 million and a one-time cash charge of $4.4 million, of which Alliant Energy Corporation funded the substantial majority. The phantom equity plan is now terminated.

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⁽³⁾

We generated Section 29 tax credits of $6.6 million in 2001 and $5.4 million in 2002. Section 29 tax credit provisions of the Internal Revenue Code expired as of December 31, 2002. In 2002, we were able to use our $5.4 million of Section 29 tax credits in the consolidated federal income tax return filed by Alliant Energy, but since these credits would not have been used in a stand-alone filing, they were recorded as additional paid-in capital as opposed to a reduction in income tax expense.

⁽⁴⁾	In 2003, we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” This was a one-time charge to net income.

⁽⁵⁾

In 2003, we acquired the limited partnership interests in three partnerships in which our wholly owned subsidiary is the general partner. Though disclosed as acquisitions of limited partnership interests in our consolidated statements of cash flows, these amounts are recorded as oil and natural gas properties on our consolidated balance sheets and are included in capital expenditures in this summary historical financial information.

⁽⁶⁾

For the purpose of calculating the ratio of earnings to fixed charges, earnings consist of income before income taxes, fixed charges and amortization of capitalized interest, less capitalized interest. Fixed charges consist of interest expensed, interest capitalized, amortized premiums, discounts and capitalized expenses related to indebtedness and an estimate of interest within rental expense.

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Summary Historical Reserve and Operating Data

The following table presents summary information regarding our estimated net proved oil and natural gas reserves as of December 31, 2001, 2002 and 2003 and our historical operating data for the years ended December 31, 2001, 2002 and 2003 and the three months ended March 31, 2004 and 2003. All calculations of estimated net proved reserves have been made in accordance with the rules and regulations of the Securities and Exchange Commission, or the SEC, and, except as otherwise indicated, give no effect to federal or state income taxes. For additional information regarding our reserves, please read “Business and Properties—Summary of Oil and Natural Gas Properties and Projects” and note 10 to our financial statements.


	As of December 31,
	2003		2002		2001
Reserve Data:
Total estimated net proved reserves:
Natural gas (Bcf)		231.0		236.0		227.5
Oil (MMbbls)		34.6		29.5		14.8
Total (Bcfe)		438.8		412.7		316.3
Estimated net proved developed reserves:
Natural gas (Bcf)		171.9		167.6		136.8
Oil (MMbbls)		26.2		23.8		11.0
Total (Bcfe)		328.9		310.4		202.8
Estimated future net revenues before income taxes (in millions)	$	1,352.2	$	1,112.4	$	425.6
Present value of estimated future net revenues before income taxes (in millions)⁽¹⁾⁽²⁾	$	784.6	$	638.6	$	244.6
Standardized measure of discounted future net cash flows (in millions)⁽³⁾	$	589.6	$	476.0	$	211.7


	Three Months Ended March 31,				Year Ended December 31,
	2004		2003		2003		2002		2001
Operating Data:
Net Production:
Natural gas (Bcf)		5.5		5.4		21.6		21.4		19.8
Oil (MMbbls)		0.6		0.6		2.6		2.3		2.1
Total (Bcfe)		9.4		9.2		37.2		35.2		32.4
Net sales (in millions)⁽⁴⁾:
Natural gas	$	27.6	$	30.1	$	104.4	$	68.6	$	75.4
Oil	$	20.0	$	19.3		71.3		54.1		49.8
Total	$	47.6	$	49.4		175.7		122.7		125.2
Average sales price:
Natural gas (per Mcf)⁽⁴⁾	$	5.00	$	5.60	$	4.78	$	3.21	$	3.82
Oil (per Bbl)⁽⁴⁾	$	30.86	$	30.17		27.50		23.35		23.85
Total (Mcfe)⁽⁴⁾	$	5.06	$	5.36		4.73		3.48		3.88
Average (per Mcfe):
Lease operating expenses	$	1.12	$	1.16	$	1.16	$	0.93	$	0.92
Production taxes	$	0.32	$	0.33	$	0.29	$	0.21	$	0.20
Depreciation, depletion and amortization expenses ⁽⁵⁾	$	1.14	$	1.15	$	1.11	$	1.24	$	1.11
General and administrative expenses, net of reimbursements	$	0.43	$	0.35	$	0.34	$	0.34	$	0.34
Net income	$	1.02	$	0.39	$	0.49	$	0.22	$	1.28

⁽¹⁾	The present value of estimated future net revenues attributable to our reserves was prepared using constant prices, as of the calculation date, discounted at 10% per year on a pre-tax basis.

⁽²⁾

The December 31, 2003 amount was calculated using a period end average realized oil price of $29.43 per barrel and a period end average realized natural gas price of $5.52 per Mcf, and the December 31, 2002 amount was calculated using a period end average realized oil price of $28.21 per barrel and a period end average realized natural gas price of $4.39 per Mcf.

⁽³⁾	The standardized measure of discounted future net cash flows represents the present value of future cash flows after income tax discounted at 10%.

⁽⁴⁾	Before consideration of hedging transactions.

⁽⁵⁾

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RISK FACTORS

You should carefully consider each of the risks described below, together with all of the other information contained in this prospectus, before deciding to exchange your old notes for new notes. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected and you may lose all or part of your investment.

Risks Relating to the Exchange Offer and the New Notes

You may have difficulty selling the old notes that you do not exchange.

If you do not exchange your old notes for the new notes offered in the exchange offer, then you will continue to be subject to the restrictions on transfer of your old notes. Those transfer restrictions are described in the indenture governing the new notes and in the legend contained on the old notes, and arose because we originally issued the old notes under exemptions from, and in transactions not subject to, the registration requirements of the Securities Act.

In general, you may offer or sell your old notes only if they are registered under the Securities Act and applicable state securities laws, or if they are offered and sold under an exemption from those requirements. We do not intend to register the old notes under the Securities Act.

If a large number of old notes are exchanged for new notes issued in the exchange offer, then it may be more difficult for you to sell your unexchanged old notes. In addition, if you do not exchange your old notes in the exchange offer, then you will no longer be entitled to have those notes registered under the Securities Act.

See “The Exchange Offer—Consequences of Failing to Exchange Old Notes” for a discussion of the possible consequences of failing to exchange your old notes.

Our debt level and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations and business prospects and prevent us from fulfilling our obligations under the new notes.

As of March 31, 2004, after giving effect to the offering of the old notes and the application of the net proceeds therefrom, we would have had approximately $153.1 million in outstanding consolidated indebtedness and $193.9 million of available borrowing capacity under Whiting Oil and Gas Corporation’s credit agreement. We are currently in the process of executing an amendment and restatement of Whiting Oil and Gas Corporation’s credit agreement intended to, among other things, increase our borrowing capacity and permit our acquisition of Equity Oil Company. See “Description of Other Indebtedness.” If our pending acquisition of Equity Oil Company is completed, Whiting Oil and Gas Corporation expects to incorporate into its credit agreement the senior debt outstanding under Equity’s credit facility, which was approximately $29.0 million as of March 31, 2004. See “Summary—Acquisition of Equity Oil Company.” We are permitted to incur additional indebtedness, provided we meet certain requirements in the indenture governing the new notes and Whiting Oil and Gas Corporation’s credit agreement.

Our level of indebtedness, and the covenants contained in the agreements governing our debt, could have important consequences on our operations, including:

•

making it more difficult for us to satisfy our obligations under the new notes or other debt and increasing the risk that we may default on our debt obligations;

•

requiring us to dedicate a substantial portion of our cash flow from operations to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;

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•

limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities;

•

limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•

detracting from our ability to withstand successfully a downturn in our business or the economy generally;

•

placing us at a competitive disadvantage against other less leveraged competitors; and

•

making us vulnerable to increases in interest rates, because debt under Whiting Oil and Gas Corporation’s credit agreement may be at variable rates.

We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the acceleration of our repayment of outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions. Moreover, the borrowing base limitation on Whiting Oil and Gas Corporation’s credit agreement is periodically redetermined based on an evaluation of our reserves. Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to repay a portion of our bank debt.

We may not have sufficient funds to make such repayments. If we are unable to repay our debt out of cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to generate sufficient cash flow to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt. The terms of our debt, including Whiting Oil and Gas Corporation’s credit agreement, may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offering or other financing. We cannot assure you that any such offering, refinancing or sale of assets can be successfully completed.

The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business.

The indenture governing the new notes and Whiting Oil and Gas Corporation’s credit agreement contain various restrictive covenants that limit our management’s discretion in operating our business. In particular, these agreements will limit our and our subsidiaries’ ability to, among other things:

•

pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our subordinated debt;

•

make loans to others;

•

make investments;

•

incur additional indebtedness or issue preferred stock;

•

create certain liens;

•

sell assets;

•

enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;

•

consolidate, merge or transfer all or substantially all of the assets of us and our restricted subsidiaries taken as a whole;

•

engage in transactions with affiliates;

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•

enter into hedging contracts;

•

create unrestricted subsidiaries; and

•

enter into sale and leaseback transactions.

In addition, Whiting Oil and Gas Corporation’s credit agreement also requires us to maintain a certain working capital ratio and a certain debt to EBITDAX ratio (as defined in the credit agreement).

If we fail to comply with the restrictions in the indenture governing the new notes or Whiting Oil and Gas Corporation’s credit agreement or any other subsequent financing agreements, a default may allow the creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders may be able to terminate any commitments they had made to make available further funds.

As a holding company, we rely on payments from our operating subsidiary in order for us to make payments on the new notes.

Whiting Petroleum Corporation is a holding company with no significant operations of its own. Because our operations are conducted through Whiting Oil and Gas Corporation, our operating subsidiary, we depend on dividends, advances and other payments from our subsidiary in order to allow us to satisfy our financial obligations. Our subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts to us, whether by dividends, advances or other payments. The ability of our subsidiaries to pay dividends and make other payments to us depends on their earnings, capital requirements and general financial conditions and is restricted by, among other things, Whiting Oil and Gas Corporation’s credit agreement, applicable corporate and other laws and regulations as well as agreements to which our subsidiaries may be a party. Specifically, Whiting Oil and Gas Corporation’s credit agreement allows it to make payments to us so that we may pay interest on the new notes, but does not allow for payments from it to us to pay principal on the new notes. Whiting Oil and Gas Corporation’s credit agreement also prohibits Whiting Oil and Gas Corporation from allowing us to make any principal payments on the new notes. Although our subsidiary guarantors are guaranteeing the new notes, each guarantee is subordinated to all senior debt of the relevant subsidiary guarantor.

We may not be able to repurchase the new notes upon a change of control.

Upon the occurrence of certain change of control events, holders of the new notes may require us to repurchase all or any part of their new notes. We may not have sufficient funds at the time of the change of control to make the required repurchases of the new notes. Additionally, certain events that would constitute a “change of control” (as defined in the indenture) would constitute an event of default under Whiting Oil and Gas Corporation’s credit agreement that would, if it should occur, permit the lenders to accelerate the debt outstanding under such credit agreement and that, in turn, would cause an event of default under the indenture. We would not be permitted to repurchase the new notes prior to termination of and payment in full of the obligations under Whiting Oil and Gas Corporation’s credit agreement.

The source of funds for any repurchase required as a result of any change of control will be our available cash or cash generated from oil and gas operations or other sources, including borrowings, sales of assets, sales of equity or funds provided by a new controlling entity. We cannot assure you, however, that sufficient funds would be available at the time of any change of control to make any required repurchases of the notes tendered and to repay debt under Whiting Oil and Gas Corporation’s credit agreement. Furthermore, using available cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future. Any future credit agreements or other agreements relating to debt to which we may become a party will most likely contain similar restrictions and provisions.

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The new notes and the subsidiary guarantees are subordinated to the senior debt of us and the subsidiary guarantors, respectively, and are effectively subordinated to our and the subsidiary guarantors’ secured debt.

The new notes will be our senior subordinated obligations. Accordingly, the new notes will be subordinated to all of our existing and future senior debt, including our guarantee of borrowings under Whiting Oil and Gas Corporation’s credit agreement. We and our subsidiaries expect to incur additional senior debt from time to time in the future, whether under Whiting Oil and Gas Corporation’s credit agreement or otherwise. The indenture governing the new notes limits, but does not prohibit, the incurrence of any other debt by us or our subsidiaries, including senior debt. As a result of such subordination, upon any distribution to our creditors in a liquidation, dissolution, bankruptcy, reorganization or any similar proceeding by or relating to us or our property, the holders of our senior debt would be entitled to receive payment in full before the holders of the new notes would be entitled to receive any payment. In addition, all payments on the new notes could be blocked in the event of a default on our senior debt. See “Description of the New Notes—Subordination.”

The new notes will not be secured. The borrowings under Whiting Oil and Gas Corporation’s credit agreement are secured by liens on Whiting Oil and Gas Corporation’s assets. If we, Whiting Oil and Gas Corporation or any of our other subsidiary guarantors liquidates, dissolves or declares bankruptcy, or if payment under the credit agreement or any of our other secured debt is accelerated, our secured lenders would be entitled to exercise the remedies available to a secured lender under applicable law and will have a claim on those assets before the holders of the new notes. As a result, the new notes and the subsidiary guarantees are effectively subordinated to our and the subsidiary guarantors’ secured debt to the extent of the value of the assets securing that debt, and the holders of the new notes would in all likelihood recover ratably less than the lenders of such secured debt in the event of our bankruptcy, liquidation or dissolution. As of March 31, 2004, after giving effect to the offering of the old notes and the use of proceeds therefrom, we and the subsidiary guarantors would have had no secured debt outstanding to which the new notes and the subsidiary guarantees would have been effectively subordinated, except for approximately $1.1 million of secured debt under Whiting Oil and Gas Corporation’s credit agreement. Approximately $193.9 million of secured debt would have been available for borrowing under the credit agreement.

The new notes will also be effectively subordinated to claims of creditors (other than us) of any of our subsidiaries that are not subsidiary guarantors of the new notes, including lessors, trade creditors, taxing authorities, creditors holding guarantees and tort claimants. In the event of a liquidation, reorganization or similar proceeding relating to a subsidiary that is not a guarantor of the new notes, these persons generally will have priority as to the assets of that subsidiary over our claims and equity interest and, thereby indirectly, holders of our debt, including the new notes.

Your ability to transfer the notes may be limited by the absence of an active trading market, and there is no assurance that any active trading market will develop for the notes.

The new notes are a new issue of securities for which there is no established public market. We do not intend to have the notes listed on a national securities exchange or included on any automated dealer quotation system. The initial purchasers have advised us that they intend to make a market in the old note and the new notes, as permitted by applicable laws and regulations; however, the initial purchasers are not obligated to make a market in the old notes or the new notes, and they may discontinue their market-making activities at any time without notice. Therefore, we cannot assure you that an active market for the old notes or the new notes will develop or, if developed, that it will continue. Historically, the market for noninvestment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the notes. We cannot assure you that the market, if any, for the old notes or the new notes will be free from similar disruptions or that any such disruptions may not adversely affect the prices at which you may sell your notes. In addition, subsequent to their initial issuance, the new notes may trade at a discount from their initial offering price, depending upon prevailing interest rates, the market for similar notes, our performance and other factors.

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Any subsidiary guarantees of the new notes may be further subordinated or avoided by a court.

Certain of our subsidiaries will jointly and severally guarantee the new notes on a senior subordinated basis. Various applicable fraudulent conveyance laws have been enacted for the protection of creditors. A court may use those laws to further subordinate or avoid any guarantee of the new notes issued by any of our subsidiaries.

A court could avoid or further subordinate the guarantee of the new notes by any of our subsidiaries in favor of that subsidiary’s other debts or liabilities to the extent that the court determined either of the following were true at the time the subsidiary issued the guarantee:

•

that subsidiary incurred the guarantee with the intent to hinder, delay or defraud any of its present or future creditors or that such subsidiary contemplated insolvency with a design to favor one or more creditors to the total or partial exclusion of others; or

•

that subsidiary did not receive fair consideration or reasonably equivalent value for issuing the guarantee and, at the time it issued the guarantee, that subsidiary:

•

was insolvent or rendered insolvent by reason of the issuance of the guarantee;

•

was engaged or about to engage in a business or transaction for which the remaining assets of that subsidiary constituted unreasonably small capital; or

•

intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they matured.

Among other things, a legal challenge of a subsidiary’s guarantee of the new notes on fraudulent conveyance grounds may focus on the benefits, if any, realized by that subsidiary as a result of our issuance of the notes. To the extent a subsidiary’s guarantee of the new notes is avoided as a result of fraudulent conveyance or held unenforceable for any other reason, the note holders would cease to have any claim in respect of that guarantee and would be creditors solely of ours.

Risks Relating to the Oil and Natural Gas Industry and Our Business

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operation and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

•

changes in global supply and demand for oil and natural gas;

•

the actions of the Organization of Petroleum Exporting Countries, or OPEC;

•

the price and quantity of imports of foreign oil and natural gas;

•

political conditions, including embargoes, in or affecting other oil-producing activity;

•

the level of global oil and natural gas exploration and production activity;

•

the level of global oil and natural gas inventories;

•

weather conditions;

•

technological advances affecting energy consumption; and

•

the price and availability of alternative fuels.

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Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Please read “—Reserve estimates depend on many assumptions that may turn out to be inaccurate …” for a discussion of the uncertainty involved in these processes. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:

•

delays imposed by or resulting from compliance with regulatory requirements;

•

pressure or irregularities in geological formations;

•

shortages of or delays in obtaining equipment and qualified personnel;

•

equipment failures or accidents;

•

adverse weather conditions, such as hurricanes and tropical storms;

•

reductions in oil and natural gas prices;

•

title problems; and

•

limitations in the market for oil and natural gas.

Our acquisition activities may not be successful.

As part of our growth strategy, we may make acquisitions of businesses and properties. However, suitable acquisition candidates may not be available on terms and conditions we find acceptable, and acquisitions pose substantial risks to our business, financial condition and results of operations. In pursuing acquisitions, we compete with other companies, many of which have greater financial and other resources to acquire attractive companies and properties. Even if future acquisitions are completed, the following are some of the risks associated with acquisitions, including our proposed acquisition of Equity Oil Company:

•

some of the acquired businesses or properties may not produce revenues, reserves, earnings or cash flow at anticipated levels;

•

we may assume liabilities that were not disclosed or that exceed our estimates;

•

we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;

•

acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and

•

we may incur additional debt related to future acquisitions.

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Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.

In order to finance acquisitions of additional producing properties, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments or other means. These changes in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or other transactions can change the character of our operations and business. The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. Furthermore, we may not be able to obtain external funding for any such acquisitions or other transactions or to obtain external funding on terms acceptable to us.

Properties that we buy may not produce as projected, and we may be unable to identify liabilities associated with the properties or obtain protection from sellers against them.

Our business strategy includes a continuing acquisition program. The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following:

•

the amount of recoverable reserves;

•

future oil and natural gas prices;

•

estimates of operating costs;

•

estimates of future development costs;

•

estimates of the costs and timing of plugging and abandonment; and

•

potential environmental and other liabilities.

Our assessment will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. In the course of our due diligence, we may not inspect every well, platform or pipeline. Inspections may not reveal structural and environmental problems, such as pipeline corrosion or groundwater contamination, when they are made. We may not be able to obtain contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.

Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present

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value of reserves shown in this prospectus. Please read “Business and Properties—Summary of Oil and Natural Gas Properties and Projects” for information about our oil and natural gas reserves.

In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this prospectus. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our proved reserves referred to in this prospectus is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. If natural gas prices decline by $0.10 per Mcf, then the pre-tax PV10% value of our proved reserves as of January 1, 2004 would decrease from $784.6 million to $773.2 million. If oil prices decline by $1.00 per barrel, then the pre-tax PV10% value of our proved reserves as of January 1, 2004 would decrease from $784.6 million to $770.0 million.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

We describe some of our current prospects and our plans to explore those prospects in this prospectus. A prospect is a property on which we have identified what our geoscientists believe, based on available seismic and geological information, to be indications of oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

•

environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

•

abnormally pressured formations;

•

mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

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•

fires and explosions;

•

personal injuries and death; and

•

natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our company. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, then it could adversely affect us.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipeline or gathering system capacity. If that were to occur, then we would be unable to realize revenue from those wells until production arrangements were made to deliver to market.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

Exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:

•

discharge permits for drilling operations;

•

drilling bonds;

•

reports concerning operations;

•

the spacing of wells;

•

unitization and pooling of properties; and

•

taxation.

Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.

Our operations may incur substantial liabilities to comply with the environmental laws and regulations.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities, and concentration of materials that can be released into the environment in connection with

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drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, incurrence of investigatory or remedial obligations, or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly material handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position, or financial condition as well as those of the oil and natural gas industry in general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed. Federal law and some state laws also allow the government to place a lien on real property for costs incurred by the government to address contamination on the property.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production.

The loss of senior management or technical personnel could adversely affect us.

To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including James J. Volker, our President and Chief Executive Officer, James R. Casperson, our Chief Financial Officer, James T. Brown, our Vice President, Operations, John R. Hazlett, our Vice President, Acquisitions and Land or Mark R. Williams, our Vice President, Exploration and Development, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.

Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our development and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to compete.

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly

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competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

Our use of oil and natural gas price hedging contracts involves credit risk and may limit future revenues from price increases and result in significant fluctuations in our net income.

We enter into hedging transactions for our oil and natural gas production to reduce our exposure to fluctuations in the price of oil and natural gas. Our hedging transactions have to date consisted of financially settled crude oil and natural gas forward sales contracts with major financial institutions. We have contracts maturing in 2004 covering the sale of 6.15 million MMbtu of natural gas and 1,200,000 barrels of oil. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure about Market Risk” for pricing and a more detailed discussion of our hedging transactions.

We may in the future enter into these and other types of hedging arrangements to reduce our exposure to fluctuations in the market prices of oil and natural gas. Hedging transactions expose us to risk of financial loss in some circumstances, including if production is less than expected, the other party to the contract defaults on its obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. Hedging transactions may limit the benefit we would have otherwise received from increases in the price for oil and natural gas. Furthermore, if we do not engage in hedging transactions, then we may be more adversely affected by declines in oil and natural gas prices than our competitors who engage in hedging transactions. Additionally, hedging transactions may expose us to cash margin requirements.

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FORWARD-LOOKING STATEMENTS

This prospectus 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 prospectus, 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, including our ability to realize cost savings from the pending merger with Equity Oil Company; 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 Whiting Oil and Gas Corporation’s credit agreement; 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; risks arising out of our hedging transactions; and other risks described under the caption “Risk Factors”. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this prospectus.

USE OF PROCEEDS

The exchange offer is intended to satisfy our obligations under the registration rights agreement entered into in connection with the issuance of the old notes. We will not receive any cash proceeds from the issuance of the new notes. We used the net proceeds of approximately $143.9 million from the sale of the old notes to refinance debt outstanding under Whiting Oil and Gas Corporation’s credit agreement.

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CAPITALIZATION

The following table sets forth our capitalization as of March 31, 2004, on an actual basis and as adjusted to give effect to the offering of the old notes and the application of the net proceeds from that offering.


	March 31, 2004
	Actual			As Adjusted
	(dollars in thousands)
Cash and cash equivalents	$	16,379		$	16,379

Long-term debt:
Whiting Oil and Gas Corporation credit agreement	$	145,000		$	1,110
Note payable to Alliant Energy Corporation		3,055			3,055
7 1/4% senior subordinated notes ⁽¹⁾		—			148,890

Total debt	$	148,055		$	153,055
Stockholders’ equity:
Common stock: $0.001 par value, 75,000,000 shares authorized, 18,842,171 shares issued and outstanding	$	19		$	19
Preferred Stock: $0.001 par value, 5,000,000 shares authorized, no shares issued or outstanding		—			—
Additional paid-in capital		172,307			172,307
Retained earnings		99,053			99,053
Deferred compensation		(1,875	)		(1,875	)
Accumulated other comprehensive income		1,820			1,820

Total stockholders’ equity	$	271,324		$	271,324

Total capitalization	$	419,379		$	424,379

⁽¹⁾	Represents $150.0 million of 7 1/4% senior subordinated notes due 2012.

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THE EXCHANGE OFFER

Purpose and Effect; Registration Rights

We issued and sold the old notes on May 11, 2004 in transactions exempt from the registration requirements of the Securities Act. Therefore, the old notes are subject to significant restrictions on resale. In connection with the issuance of the old notes, we entered into a registration rights agreement, which required that we and the subsidiary guarantors:

•

file with the SEC a registration statement under the Securities Act relating to the exchange offer and the issuance and delivery of new notes in exchange for the old notes;

•

use our reasonable best efforts to cause the SEC to declare the exchange offer registration statement effective under the Securities Act; and

•

consummate the exchange offer not later than 40 days following the effective date of the exchange offer registration statement.

If you participate in the exchange offer, then you will, with limited exceptions, receive new notes that are freely tradeable and not subject to restrictions on transfer. You should read this prospectus under the heading “— Resales of New Notes” for more information relating to your ability to transfer new notes.

If you are eligible to participate in the exchange offer and do not tender your old notes, then you will continue to hold the untendered old notes, which will continue to be subject to restrictions on transfer under the Securities Act.

The exchange offer is intended to satisfy our exchange offer obligations under the registration rights agreement. The above summary of the registration rights agreement is not complete. You are encouraged to read the full text of the registration rights agreement, which has been filed as an exhibit to the registration statement that includes this prospectus.

Terms of the Exchange Offer

We are offering to exchange $150,000,000 in aggregate principal amount of our 7 ¼% Senior Subordinated Notes due 2012 that we have registered under the Securities Act for a like principal amount of our outstanding unregistered 7 ¼% Senior Subordinated Notes due 2012.

Upon the terms and subject to the conditions set forth in this prospectus and in the accompanying letter of transmittal, we will accept all old notes validly tendered and not withdrawn before 5:00 p.m., New York City time, on the expiration date of the exchange offer. We will issue $1,000 principal amount of new notes in exchange for each $1,000 principal amount of outstanding old notes we accept in the exchange offer. You may tender some or all of your old notes under the exchange offer. However, the old notes are issuable in authorized denominations of $1,000 and integral multiples thereof. Accordingly, old notes may be tendered only in denominations of $1,000 and integral multiples thereof. The exchange offer is not conditioned upon any minimum amount of old notes being tendered.

The form and terms of the new notes will be the same as the form and terms of the old notes, except that:

•

the new notes will be registered under the Securities Act and thus will not be subject to the restrictions on transfer or bear legends restricting their transfer;

•

all of the new notes will be represented by global notes in book-entry form unless exchanged for notes in definitive certificated form under the limited circumstances described under “Description of the New Notes -Book-Entry, Delivery and Form;” and

•

the new notes will not provide for the payment of additional interest under circumstances relating to the timing of the exchange offer.

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The new notes will evidence the same debt as the old notes and will be issued under, and be entitled to the benefits of, the indenture governing the old notes.

The new notes will accrue interest from the most recent date to which interest has been paid on the old notes or, if no interest has been paid, from the date of issuance of the old notes. Accordingly, registered holders of new notes on the record date for the first interest payment date following the completion of the exchange offer will receive interest accrued from the most recent date to which interest has been paid on the old notes or, if no interest has been paid, from the date of issuance of the old notes. However, if that record date occurs prior to completion of the exchange offer, then the interest payable on the first interest payment date following the completion of the exchange offer will be paid to the registered holders of the old notes on that record date.

In connection with the exchange offer, you do not have any appraisal or dissenters’ rights under the Delaware General Corporation Law or the indenture. We intend to conduct the exchange offer in accordance with the registration rights agreement and the applicable requirements of the Securities Act of 1933, the Securities Exchange Act of 1934 and the rules and regulations of the SEC. The exchange offer is not being made to, nor will we accept tenders for exchange from, holder of the old notes in any jurisdiction in which the exchange offer or the acceptance of it would not be in compliance with the securities or blue sky laws of the jurisdiction.

We will be deemed to have accepted validly tendered old notes when we have given oral or written notice of our acceptance to the exchange agent. The exchange agent will act as agent for the tendering holders for the purpose of receiving the new notes from us.

If we do not accept any tendered old notes because of an invalid tender or for any other reason, then we will return certificates for any unaccepted old notes without expense to the tendering holder as promptly as practicable after the expiration date.

Expiration Date; Amendments

The exchange offer will expire at 5:00 p.m., New York City time, on July 9, 2004, unless we, in our sole discretion, extend the exchange offer.

If we determine to extend the exchange offer, then we will notify the exchange agent of any extension by oral or written notice and give each registered holder notice of the extension by means of a press release or other public announcement before 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date.

We reserve the right, in our sole discretion, to delay accepting any old notes, to extend the exchange offer or to amend or terminate the exchange offer if any of the conditions described below under “- Conditions” have not been satisfied or waived by giving oral or written notice to the exchange agent of the delay, extension, amendment or termination. Further, we reserve the right, in our sole discretion, to amend the terms of the exchange offer in any manner. We will notify you as promptly as practicable of any extension, amendment or termination. We will also file a post-effective amendment to the registration statement of which this prospectus is a part with respect to any fundamental change in the exchange offer.

Procedures for Tendering Old Notes

Any tender of old notes that is not withdrawn prior to the expiration date will constitute a binding agreement between the tendering holder and us upon the terms and subject to the conditions set forth in this prospectus and in the accompanying letter of transmittal. A holder who wishes to tender old notes in the exchange offer must do either of the following:

•

properly complete, sign and date the letter of transmittal, including all other documents required by the letter of transmittal; have the signature on the letter of transmittal guaranteed if the letter of transmittal so requires; and deliver that letter of transmittal and other required documents to the exchange agent at the address listed below under “- Exchange Agent” on or before the expiration date; or

- 25 -

•

if the old notes are tendered under the book-entry transfer procedures described below transmit to the exchange agent on or before the expiration date an agent’s message.

In addition, one of the following must occur:

•

the exchange agent must receive certificates representing your old notes along with the letter of transmittal on or before the expiration date, or

•

the exchange agent must receive a timely confirmation of book-entry transfer of the old notes into the exchange agent’s account at The Depository Trust Company of New York City, or DTC, under the procedure for book-entry transfers described below along with the letter of transmittal or a properly transmitted agent’s message, on or before the expiration date; or

•

the holder must comply with the guaranteed delivery procedures described below.

The term “agent’s message” means a message, transmitted by a book-entry transfer facility to and received by the exchange agent and forming a part of the book-entry confirmation, which states that the book-entry transfer facility has received an express acknowledgement from the tendering DTC participant stating that the participant has received and agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against the participant.

The method of delivery of old notes, the letter of transmittal and all other required documents to the exchange agent is at your election and risk. Rather than mail these items, we recommend that you use an overnight or hand delivery service. In all cases, you should allow sufficient time to assure timely delivery to the exchange agent before the expiration date. Do not send letters of transmittal or old notes to us.

Generally, an eligible institution must guarantee signatures on a letter of transmittal or a notice of withdrawal unless the old notes are tendered:

•

by a registered holder of the old notes who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal; or

•

for the account of an eligible institution.

If signatures on a letter of transmittal or a notice of withdrawal are required to be guaranteed, the guarantee must be by a firm which is:

•

a member of a registered national securities exchange;

•

a member of the National Association of Securities Dealers, Inc.;

•

a commercial bank or trust company having an office or correspondent in the United States; or

•

another “eligible institution” within the meaning of Rule l7Ad-15 under the Securities Exchange Act.

If the letter of transmittal is signed by a person other than the registered holder of any outstanding old notes, the original notes must be endorsed or accompanied by appropriate powers of attorney. The power of attorney must be signed by the registered holder exactly as the registered holder(s) name(s) appear(s) on the old notes and an eligible institution must guarantee the signature on the power of attorney.

If the letter of transmittal, or any old notes or powers of attorney are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, these persons should so indicate when signing. Unless waived by us, they should also submit evidence satisfactory to us of their authority to so act.

- 26 -

If you wish to tender old notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, you should promptly instruct the registered holder to tender on your behalf. If you wish to tender on your behalf, you must, before completing the procedures for tendering old notes, either register ownership of the old notes in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time.

We will determine in our sole discretion all questions as to the validity, form, eligibility, including time of receipt, and acceptance of old notes tendered for exchange. Our determination will be final and binding on all parties. We reserve the absolute right to reject any and all tenders of old notes not properly tendered or old notes our acceptance of which might, in the judgment of our counsel, be unlawful. We also reserve the absolute right to waive any defects, irregularities or conditions of tender as to any particular old notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within the time period we determine. Neither we, the exchange agent nor any other person will incur any liability for failure to give you notification of defects or irregularities with respect to tenders of your old notes.

By tendering, you will represent to us that:

•

any new notes that the holder receives will be acquired in the ordinary course of its business;

•

the holder has no arrangement or understanding with any person or entity to participate in the distribution of the new notes;

•

if the holder is not a broker- dealer, that it is not engaged in and does not intend to engage in the distribution of the new notes;

•

if the holder is a broker- dealer, that the holder’s old notes were acquired as a result of market-making activities or other trading activities; and

•

the holder is not our “affiliate,” as defined in Rule 405 of the Securities Act, or, if the holder is our affiliate, it will comply with any applicable registration and prospectus delivery requirements of the Securities Act.

If any holder or any such other person is our “affiliate,” or is engaged in or intends to engage in or has an arrangement or understanding with any person to participate in a distribution of the new notes to be acquired in the exchange offer, then that holder or any such other person:

•

may not rely on the applicable interpretations of the staff of the SEC;

•

is not entitled and will not be permitted to tender old notes in the exchange offer; and

•

must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

Each broker-dealer who acquired its old notes as a result of market-making activities or other trading activities and thereafter receives new notes issued for its own account in the exchange offer, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes issued in the exchange offer. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. See “Plan of Distribution” for a discussion of the exchange and resale obligations of broker-dealers in connection with the exchange offer.

Any broker-dealer that acquired old notes directly from us may not rely on the applicable interpretations of the staff of the SEC and must comply with the registration and delivery requirements of the Securities Act (including being named as a selling securityholder) in connection with any resales of the old notes or the new notes.

- 27 -

Acceptance of Old Notes for Exchange; Delivery of New Notes

Upon satisfaction of all conditions to the exchange offer, we will accept, promptly after the expiration date, all old notes properly tendered and will issue the new notes promptly after acceptance of the old notes.

For purposes of the exchange offer, we will be deemed to have accepted properly tendered old notes for exchange when we have given oral or written notice of that acceptance to the exchange agent. For each old note accepted for exchange, you will receive a new note having a principal amount equal to that of the surrendered old note.

In all cases, we will issue new notes for old notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:

•

certificates for your old notes or a timely confirmation of book-entry transfer of your old notes into the exchange agent’s account at DTC; and

•

a properly completed and duly executed letter of transmittal and all other required documents or a properly transmitted agent’s message.

If we do not accept any tendered old notes for any reason set forth in the terms of the exchange offer or if you submit old notes for a greater principal amount than you desire to exchange, we will return the unaccepted or non-exchanged old notes without expense to you. In the case of old notes tendered by book-entry transfer into the exchange agent’s account at DTC under the book-entry procedures described below, we will credit the non-exchanged old notes to your account maintained with DTC.

Book-Entry Transfer

We understand that the exchange agent will make a request within two business days after the date of this prospectus to establish accounts for the old notes at DTC for the purpose of facilitating the exchange offer, and any financial institution that is a participant in DTC’s system may make book-entry delivery of old notes by causing DTC to transfer the old notes into the exchange agent’s account at DTC in accordance with DTC’s procedures for transfer. Although delivery of old notes may be effected through book-entry transfer at DTC, the exchange agent must receive a properly completed and duly executed letter of transmittal with any required signature guarantees, or an agent’s message instead of a letter of transmittal, and all other required documents at its address listed below under “- Exchange Agent” on or before the expiration date, or if you comply with the guaranteed delivery procedures described below, within the time period provided under those procedures.

Guaranteed Delivery Procedures

If you wish to tender your old notes and your old notes are not immediately available, or you cannot deliver your old notes, the letter of transmittal or any other required documents or comply with DTC’s procedures for transfer before the expiration date, then you may participate in the exchange offer if:

•

the tender is made through an eligible institution;

•

before the expiration date, the exchange agent receives from the eligible institution a properly completed and duly executed notice of guaranteed delivery, substantially in the form provided by us, by facsimile transmission, mail or hand delivery, containing:

•

the name and address of the holder and the principal amount of old notes tendered,

•

a statement that the tender is being made thereby, and

•

a guarantee that within three New York Stock Exchange trading days after the expiration date, the certificates representing the old notes in proper form for transfer or a book-entry confirmation and any other documents required by the letter of transmittal will be deposited by the eligible institution with the exchange agent; and

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•

the exchange agent receives the properly completed and executed letter of transmittal as well as certificates representing all tendered old notes in proper form for transfer, or a book-entry confirmation, and all other documents required by the letter of transmittal within three New York Stock Exchange trading days after the expiration date.

Withdrawal Rights

You may withdraw your tender of old notes at any time before the exchange offer expires.

For a withdrawal to be effective, the exchange agent must receive a written notice of withdrawal at its address listed below under “- Exchange Agent.” The notice of withdrawal must:

•

specify the name of the person who tendered the old notes to be withdrawn;

•

identify the old notes to be withdrawn, including the principal amount, or, in the case of old notes tendered by book-entry transfer, the name and number of the DTC account to be credited, and otherwise comply with the procedures of DTC; and

•

if certificates for old notes have been transmitted, specify the name in which those old notes are registered if different from that of the withdrawing holder.

If you have delivered or otherwise identified to the exchange agent the certificates for old notes, then, before the release of these certificates, you must also submit the serial numbers of the particular certificates to be withdrawn and a signed notice of withdrawal with the signatures guaranteed by an eligible institution, unless the holder is an eligible institution.

We will determine in our sole discretion all questions as to the validity, form and eligibility, including time of receipt, of notices of withdrawal. Our determination will be final and binding on all parties. Any old notes so withdrawn will be deemed not to have been validly tendered for purposes of the exchange offer. We will return any old notes that have been tendered but that are not exchanged for any reason to the holder, without cost, as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer. In the case of old notes tendered by book-entry transfer into the exchange agent’s account at DTC, the old notes will be credited to an account maintained with DTC for the old notes. You may retender properly withdrawn old notes by following one of the procedures described under “- Procedures for Tendering Old Notes” at any time on or before the expiration date.

Conditions

Notwithstanding any other term of the exchange offer, we will not be required to accept for exchange, or to exchange new notes for, any old notes if:

•

the exchange offer, or the making of any exchange by a holder of old notes, would violate any applicable law or applicable interpretation by the staff of the SEC; or

•

any action or proceeding is instituted or threatened in any court or by or before any governmental agency with respect to the exchange offer which, in our judgment, would reasonably be expected to impair our ability to proceed with the exchange offer.

The conditions listed above are for our sole benefit and we may assert them regardless of the circumstances giving rise to any condition. Subject to applicable law, we may waive these conditions in our discretion in whole or in part at any time and from time to time.

We expressly reserve the right, at any time or at various times, to extend the period of time during which the exchange offer is open. Consequently, we may delay acceptance of any old notes by giving oral or written notice

- 29 -

of an extension to their holders. During an extension, all old notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange.

Exchange Agent

J.P. Morgan Trust Company, National Association, is the exchange agent for the exchange offer. You should direct any questions and requests for assistance and requests for additional copies of this prospectus, the letter of transmittal or the notice of guaranteed delivery to the exchange agent addressed as follows:

By Hand, Overnight Mail, Courier, or Registered or Certified Mail:

J.P. Morgan Trust Company, National Association

Institutional Trust Services

2001 Bryan Street, 9^th Floor

Dallas, Texas 75201

Attention: Mr. Frank Ivins

By Facsimile:

(214) 468-6494

Attention: Institutional Trust Services

Delivery of the letter of transmittal to an address other than as listed above or transmission via facsimile other than as listed above will not constitute a valid delivery of the letter of transmittal.

Fees and Expenses

We will pay the expenses of the exchange offer. We will not make any payments to brokers, dealers or others soliciting acceptances of the exchange offer. We are making the principal solicitation by mail; however, our officers and employees may make additional solicitations by facsimile transmission, e-mail, telephone or in person. You will not be charged a service fee for the exchange of your notes, but we may require you to pay any transfer or similar government taxes in certain circumstances.

Transfer Taxes

You will not be obligated to pay any transfer taxes, unless you instruct us to register new notes in the name of, or request that old notes not tendered or not accepted in the exchange offer be returned to, a person other than the registered tendering holder.

Accounting Treatment

We will record the new notes at the same carrying values as the old notes, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss on the exchange of notes. We will amortize the expenses of the offer over the term of the new notes.

Consequences of Failure to Exchange Old Notes

If you are eligible to participate in the exchange offer but do not tender your old notes, you will not have any further registration rights, except in limited circumstances with respect to specific types of holders of old notes. Old notes that are not tendered or are tendered but not accepted will, following the consummation of the exchange offer, continue to be subject to the provisions in the indenture regarding the transfer and exchange of the old notes and the existing restrictions on transfer set forth in the legend on the old notes and in the offering

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memorandum dated May 5, 2004, relating to the old notes. Accordingly, you may resell the old notes that are not exchanged only:

•

to us;

•

so long as the old notes are eligible for resale under Rule 144A under the Securities Act, to a person whom you reasonably believe is a “qualified institutional buyer” within the meaning of Rule 144A purchasing for its own account or for the account of a qualified institutional buyer in a transaction meeting the requirements of Rule 144A;

•

in accordance with another exemption from the registration requirements of the Securities Act; or

•

under an effective registration statement under the Securities Act;

in each case in accordance with all other applicable securities laws. We do not intend to register the old notes under the Securities Act.

Old notes that are not exchanged in the exchange offer will remain outstanding and continue to accrue interest and will be entitled to the rights and benefits their holders have under the indenture relating to the old notes and the new notes. Holders of the new notes and any old notes that remain outstanding after consummation of the exchange offer will vote together as a single class for purposes of determining whether holders of the requisite percentage of the class have taken certain actions or exercised certain rights under the indenture.

Resales of New Notes

Based on interpretations of the staff of the SEC, as set forth in no-action letters to third parties, we believe that new notes issued under the exchange offer in exchange for old notes may be offered for resale, resold and otherwise transferred by any old note holder without further registration under the Securities Act and without delivery of a prospectus that satisfies the requirements of Section 10 of the Securities Act if:

•

the holder is not our “affiliate” within the meaning of Rule 405 under the Securities Act;

•

the new notes are acquired in the ordinary course of the holder’s business; and

•

the holder does not intend to participate in a distribution of the new notes.

Any holder who exchanges old notes in the exchange offer with the intention of participating in any manner in a distribution of the new notes must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction.

This prospectus may be used for an offer to resell, resale or other retransfer of new notes. With regard to broker-dealers, only broker-dealers that acquire the old notes as a result of market-making activities or other trading activities may participate in the exchange offer. Each broker-dealer that receives new notes for its own account in exchange for old notes, where the old notes were acquired by the broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of the new notes. Please see “Plan of Distribution” for more details regarding the transfer of new notes.

- 31 -

SELECTED HISTORICAL FINANCIAL INFORMATION

The following selected historical financial information for each of the years ended December 31, 2003, December 31, 2002, December 31, 2001 and December 31, 2000 has been derived from our audited consolidated financial statements and related notes. The following selected historical financial information for the three months ended March 31, 2004 and 2003 and the year ended December 31, 1999 has been derived from our unaudited consolidated financial statements. In the opinion of our management, the unaudited consolidated financial statements include all adjustments, consisting only of normal recurring adjustments, necessary for the fair statement of the selected historical consolidated financial data. This information is only a summary and you should read it in conjunction with material contained in the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our financial statements included elsewhere in this prospectus.


	Three Months Ended March 31,						Year Ended December 31,
	2004			2003			2003			2002			2001		2000			1999
	(dollars in millions except per share data)
Consolidated Income Statement Information:
Revenues:
Oil and gas sales	$	47.6		$	49.5		$	175.7		$	122.7		$	125.2	$	107.0		$	60.9
Gain (loss) on oil and gas hedging activities		(1.0	)		(6.7	)		(8.7	)		(3.2	)		2.3		(3.8	)		—
Gain on sale of oil and gas properties		—			—			—			1.0			11.7		7.7			10.1
Interest income and other		0.1			—			0.3			—			0.2		0.1			0.1

Total revenues	$	46.7		$	42.8		$	167.3		$	120.5		$	139.4	$	111.0		$	71.1

Costs and expenses:
Lease operating	$	10.5		$	10.7		$	43.2		$	32.9		$	29.8	$	23.8		$	20.7
Production taxes		3.0			3.0			10.7			7.4			6.5		5.4			3.0
Depreciation, depletion and amortization⁽¹⁾		10.7			10.6			41.2			43.6			26.9		21.5			19.8
Impairment of proven oil and gas properties		—			—			—			—			—		—			3.3
Exploration		0.4			0.2			3.2			1.8			0.8		1.1			1.9
Phantom equity plan⁽²⁾		—			—			10.9			—			—		—			—
General and administrative		4.0			3.2			12.8			12.0			10.9		6.3			4.3
Interest expense		2.3			3.2			9.2			10.9			10.2		7.5			5.4

Total costs and expenses	$	31.0		$	30.9		$	131.2		$	108.6		$	85.1	$	65.6		$	58.4

Income before income taxes and cumulative change	$	15.7		$	11.9		$	36.1		$	11.9		$	54.3	$	45.4		$	12.7
Income tax expense⁽³⁾		6.1			4.5			13.9			4.2			13.1		11.7			1.8

Income from continuing operations		9.6			7.5			22.2			7.7			41.2		33.7			10.9
Cumulative change in accounting principle⁽⁴⁾		—			(3.9	)		(3.9	)		—			—		—			—

Net income	$	9.6		$	3.6		$	18.3		$	7.7		$	41.2	$	33.7		$	10.9

Net income per common share from continuing operations, basic and diluted	$	0.51		$	0.40		$	1.18		$	0.41		$	2.20	$	1.80		$	0.58

Net income per common share, basic and diluted	$	0.51		$	0.19		$	0.98		$	0.41		$	2.20	$	1.80		$	0.58

Other Financial Information:
Net cash provided by operating activities	$	14.3		$	15.6		$	96.4		$	62.6		$	62.3	$	42.3		$	38.7
Capital expenditures⁽⁵⁾	$	11.5		$	5.2		$	52.0		$	165.4		$	99.6	$	139.1		$	34.9
Ratio of earnings to fixed charges⁽⁶⁾		7.62x			4.65x			4.85x			2.08x			6.10x		6.93x			3.32x

	As of March 31,						As of December 31,
	2004			2003			2003			2002			2001		2000			1999
	(dollars in millions)
Balance Sheet Information:
Total assets	$	498.6		$	467.6		$	536.3		$	448.5		$	319.8	$	256.4		$	148.5
Long-term debt	$	148.1		$	185.0		$	188.0		$	265.5		$	163.6	$	139.7		$	72.5
Stockholder’s equity	$	271.3		$	208.3		$	259.6		$	122.8		$	111.5	$	70.0		$	36.2

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⁽¹⁾

⁽²⁾

⁽³⁾

We generated Section 29 tax credits of $3.0 million in 1999, $5.2 million in 2000, $6.6 million in 2001 and $5.4 million in 2002. Section 29 tax credit provisions of the Internal Revenue Code expired as of December 31, 2002. In 2002, we were able to use our $5.4 million of Section 29 tax credits in the consolidated federal income tax return filed by Alliant Energy, but since these credits would not have been used in a stand-alone filing, they were recorded as additional paid-in capital as opposed to a reduction in income tax expense.

⁽⁴⁾	In 2003, we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” This was a one-time charge to net income.

⁽⁵⁾

⁽⁶⁾

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MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following discussion and analysis should be read in conjunction with our selected historical financial data and our accompanying financial statements and the notes to those financial statements included elsewhere in this prospectus. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this prospectus, particularly in “Risk Factors.”

Overview

We are engaged in oil and natural gas exploitation, acquisition, exploration and production activities primarily in the Gulf Coast/Permian Basin, Rocky Mountains, Michigan and Mid-Continent 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.

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

The following table sets forth selected operating data for the periods indicated:


	Three Months Ended March 31,				Years Ended December 31,
	2004		2003		2003		2002		2001
Net production:
Natural gas (Bcf)		5.5		5.4		21.6		21.4		19.8
Oil (MMbbls)		0.6		0.6		2.6		2.3		2.1
Net sales (in millions):
Natural gas⁽¹⁾	$	27.6	$	30.1	$	104.4	$	68.6	$	75.4
Oil⁽¹⁾	$	20.0	$	19.3	$	71.3	$	54.1	$	49.8
Average sales price:
Natural gas (per Mcf)⁽¹⁾	$	5.00	$	5.60	$	4.78	$	3.21	$	3.82
Oil (per Bbl)⁽¹⁾	$	30.86	$	30.17	$	27.50	$	23.35	$	23.85
Costs and expenses (per Mcfe):
Lease operating expenses	$	1.12	$	1.16	$	1.16	$	0.93	$	0.92
Production taxes	$	0.32	$	0.33	$	0.29	$	0.21	$	0.20
Depreciation, depletion and amortization expense	$	1.14	$	1.15	$	1.11	$	1.24	$	1.11
General and administrative expenses, net of reimbursements	$	0.43	$	0.35	$	0.34	$	0.34	$	0.34

⁽¹⁾	Before consideration of hedging transactions.

Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003

Oil and Natural Gas Sales. Our oil and natural gas sales revenue decreased approximately $1.8 million to $47.6 million for the first quarter of 2004. Sales in any period are a function of sales volumes and average sales prices. As shown above, our sales volumes increased 2% between periods on a Mcfe basis. The volume increase resulted from successful drilling and acquisition activities over the past year which produced new volumes that more than offset natural decline. In terms of pricing, the average natural gas price decrease of 11% created the largest downward variance and was offset to a smaller degree by a 2% increase in average oil price.

Loss on Oil and Natural Gas Hedging Activities. We hedged 46% of our natural gas volumes during the first quarter of 2004 incurring no hedging loss, and 45% of our natural gas volumes during the first quarter of 2003 incurring a hedging loss of $6.0 million. The majority of the hedging loss in 2003 occurred in the month of March when NYMEX natural gas prices reached record highs in excess of $9.00 per MMbtu. We hedged 46% of our oil volumes during the first quarter of 2004 incurring a hedging loss of $1.0 million, and 22% of our oil volumes during the first quarter of 2003 incurring a loss of $0.7 million. See “Qualitative and Quantitative Disclosures About Market Risk” for a list of currently outstanding oil and natural gas hedges.

Lease Operating Expenses. Our lease operating expenses per Mcfe decreased from $1.16 during the first quarter of 2003 to $1.12 during the same period in 2004. During 2003 we continued an extensive repair and replacement program on wells acquired during 2002. These procedures ended in late 2003 and lease operating costs have decreased to a level more reflective of ongoing operations.

Production Taxes. The production taxes we pay are generally calculated as a percent 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 within a small window of 6.0% to 6.5% of oil and natural gas sales revenue. Our production taxes for the first quarter of 2004 and 2003 were 6.3% and 6.1%, respectively, of oil and natural gas sales.

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Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $130,000 over the first quarter of 2003 to $10.7 million for the first quarter of 2004. The increase resulted from increased production offset by a small decrease in our depreciation, depletion and amortization rate. On a Mcfe basis, the rate decrease was from $1.15 in the first quarter of 2003 to $1.14 during the same period in 2004. Our depreciation, depletion and amortization rate was consistent between periods because the pricing environments were similar at each quarter end. Future changes in the pricing environment could significantly impact our depreciation, depletion and amortization 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 are as follows (in thousands):


	Three Months Ended March 31,
	2004		2003
Depletion	$	10,169	$	10,057
Depreciation		180		180
Accretion of abandonment liability		380		362

Total	$	10,729	$	10,599

Exploration Costs. Our exploration costs increased $255,000 from the first quarter of 2003 to $418,000 during the first quarter of 2004. The higher exploratory costs are related to the increased 2004 drilling budget.

General and Administrative Expenses. We report general and administrative cost net of COPAS and partnership reimbursements. The components of our general and administrative expense are as follows:


	Three Months Ended March 31,
	2004			2003
General and administrative expense	$	5,297		$	4,624
Reimbursements		(1,296	)		(1,435	)

General and administrative expense, net	$	4,001		$	3,189

General and administrative expense increased $0.8 million, to $4.0 million during the first quarter of 2004. The increase between first quarters was from $0.35 to $0.43 on a per Mcfe basis. The increase was primarily caused by the extra costs of functioning as a public company, increases in the employee base due to the continued growth of the company 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.

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


	Three Months Ended March 31,
	2004		2003
Bank borrowings	$	1,399	$	1,719
Alliant Energy Corporation		38		1,207
Amortization of debt issue costs		282		300
Accretion of tax sharing liability		600		—

Total interest expense	$	2,319	$	3,226

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The decrease in bank interest was primarily due to our $40.0 million pay down of the bank facility on February 17, 2004. The decrease in interest expense related to Alliant Energy Corporation 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 in November 2003. A further explanation of the step-up transaction is included in the “Liquidity and Capital Resources” section below.

Income Tax Expense. Our effective income tax rate was estimated at 38.6% in the first quarter of 2004, consistent with the yearly estimated effective tax rate for 2003. Prior to our initial public offering, 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 initial public offering, 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-initial public offering stub period in 2003, we do not expect to pay any federal income taxes related to the 2004 tax year

Cumulative Change in Accounting Principle. Effective January 1, 2003, we adopted the provisions of Statement of Financial Accounting Standards, or 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 is accreted at the end of each accounting period through charges to accretion expense. Upon adoption of SFAS No. 143, we recorded an increase to our discounted abandonment liability 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 $3.6 million during the first quarter of 2003 to $9.6 million during the first quarter of 2004. The primary reasons for this increase included higher crude oil and natural gas prices net of hedging between periods, higher volumes sold, lower lease operating expense and interest charges, the impact of the cumulative effect of adoption of SFAS No. 143 in 2003, offset by higher general and administrative, depreciation, depletion and amortization and exploration costs in 2004.

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

Oil and Natural Gas Sales. Oil and natural gas sales revenue increased approximately $53.0 million to $175.7 million in 2003. Natural gas sales increased $35.8 million and oil sales increased $17.2 million. The natural gas sales increase was caused by a 49% increase in the average realized natural gas price from $3.21 per Mcf in 2002 to $4.78 per Mcf in 2003 combined with a 230,000 Mcf volume increase in natural gas sales between years. The oil sales increase was caused by a sales volume increase of 275,000 Bbls in 2003 and an 18% increase in the average realized oil price from $23.35 in 2002 to $27.50 in 2003. The volume increase for oil and natural gas primarily resulted from the $217 million of capital expenditures during 2002 and 2003.

Loss on Oil and Natural Gas Hedging Activities. We hedged 41% of our natural gas volumes during 2003, incurring a hedging loss of $7.7 million, and 8% of our natural gas volumes during 2002, incurring a loss of $0.2 million. We hedged 8% of our oil volumes during 2003, incurring a hedging loss of $1.0 million, and 35% of our oil volumes during 2002, incurring a loss of $3.0 million.

Gain on Sale of Oil and Natural Gas Properties. In 2002, we divested one property, realizing a gain of $1.0 million. No significant properties were sold in 2003.

Lease Operating Expenses. Our lease operating expenses per Mcfe increased from $0.93 in 2002 to $1.16 in 2003. The increase resulted from acquisitions during 2002 that caused a larger portion of our operations to be

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located in Michigan and North Dakota, where weather conditions, sulfur content and remote locations create higher operating costs in comparison to other areas of operation.

Production Taxes. Production taxes as a percentage of oil and natural gas sales were 6.1% in 2003 and 6.0% in 2002. The small increase in the effective rate resulted from additional property purchases in the states of North Dakota and Montana, where effective production tax rates are higher on average than other areas where we own significant producing properties.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased by $2.3 million in 2003. The decrease was a result of a decrease in the average rate from $1.24 per Mcfe in 2002 to $1.11 per Mcfe in 2003, partially offset by increased sales volumes in 2003. The lower rate was a result of higher prices between periods, which allowed for a longer economic production life and corresponding increased reserve volumes and, as a result, a lower depreciation, depletion and amortization rate.

Exploration Costs. Exploration costs increased $1.4 million to $3.2 million for 2003. The increase was the result of recording three exploratory dry holes during 2003 compared to one exploratory dry hole in 2002.

General and Administrative Expenses. General and administrative expenses increased 6.9%, or $0.8 million, to $12.8 million in 2003. This increase was related to increases in compensation expense associated with increased personnel required to administer our growth and to general cost inflation.

Phantom Equity Plan Compensation. The completion of our initial public offering in November 2003 constituted a “triggering event” under our phantom equity plan. Under this plan, our employees received compensation of $10.9 million in the form of 420,000 shares of our common stock after withholding of shares by us for estimated payroll and income taxes. The phantom equity plan is now terminated.

Interest Expense. Interest expense decreased $1.7 million to $9.2 million in 2003 compared to $10.9 million in 2002. The decrease was due to lower average debt levels in 2003 and lower effective interest rates in 2003. The lower debt levels were primarily related to a March 2003 decision by Alliant Energy to convert its remaining $80.9 million of intercompany debt into our equity thereby lowering our future interest expense.

Income Tax Expense. Our effective tax rate was 38.6% in 2003 and 35.3% during 2002. The increased effective tax rate was in part due to our 2002 acquisitions in the state of North Dakota where the effective state income tax rate is higher on average than other areas where we own significant producing properties. In addition, during 2002 we generated $5.4 million of Section 29 credits that we were not able to offset against tax expense. Under our tax separation and indemnification agreement with Alliant Energy, we expect to be compensated for these credits in the future when they are utilized by Alliant Energy. Under generally accepted accounting principles, the recording of the tax credits in 2002 were required to be charged as additional paid-in capital rather than as a decrease to our 2002 income tax expense. Section 29 tax credit provisions of the Internal Revenue Code expired December 31, 2002. Therefore, unless additional legislation is passed, Section 29 credits will not be available in periods subsequent to 2002.

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 is accreted at the end of each accounting period through charges to accretion expense. The liability is discounted using a credit-adjusted risk-free rate of approximately 7%. If the obligation is settled for other than the carrying amount, a gain or loss is

- 38 -

recognized on settlement. Upon adoption of SFAS No. 143, we recorded an increase to our discounted abandonment liability 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 $7.7 million in 2002 to $18.3 million in 2003. The primary reasons for this increase included higher crude oil and natural gas prices between periods and higher volumes sold, offset by higher lease operating, tax and general and administrative costs due to our growth.

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

Oil and Natural Gas Sales. Oil and natural gas sales revenue decreased approximately $2.6 million to $122.7 million in 2002. Natural gas sales decreased $6.8 million, while oil sales increased $4.2 million. The natural gas sales decrease was caused by a 16% decline in the average realized natural gas price from $3.82 Mcf in 2001 to $3.21 Mcf in 2002, partially offset by an increase in natural gas production of 1.6 Bcf in 2002. The oil sales increase was caused by a sales volume increase of 200,000 Bbls in 2002, partially offset by a 2% decline in the average realized oil price from $23.85 in 2001 to $23.35 in 2002. The volume increase for oil and natural gas was due to $265 million of capital expenditures during 2001 and 2002.

Loss on Oil and Natural Gas Hedging Activities. We hedged 8% of our natural gas volumes during 2002, incurring a hedging loss of $0.2 million, and 11% of our natural gas volumes during 2001, incurring a gain of $1.6 million. We hedged 35% of our oil volumes during 2002, incurring a hedging loss of $3.0 million, and 17% of our oil volumes during 2001, incurring a gain of $0.7 million.

Gain on Sale of Oil and Natural Gas Properties. In 2002, we divested only one property, realizing a gain of $1.0 million, while in 2001, we divested several properties, realizing total sales gains of $11.7 million.

Lease Operating Expenses. Our lease operating expenses per Mcfe increased from $0.92 in 2001 to $0.93 in 2002. The increase resulted from acquisitions during 2002 that caused a larger portion of our operations to be located in Michigan and North Dakota, where weather conditions, sulfur content and remote locations create higher operating costs.

Production Taxes. Production taxes as a percentage of oil and natural gas sales were 6.0% in 2002 and 5.2% in 2001. The increase in the effective rate resulted from additional property purchases in the states of North Dakota and Montana, where effective production tax rates are higher on average than other areas where we own significant producing properties.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense in 2001 included a $9.0 million reduction related to the abandonment liability for the Point Arguello platform located offshore from California. During 2001, we received a revised and more detailed dismantlement plan from the operator. The $9.0 million reduction of liability was credited against depreciation, depletion and amortization expense since the liability was initially created by charges to depreciation, depletion and amortization expense. Without this credit, our depreciation, depletion and amortization expense charge for 2001 would have been $35.9 million. The increase to $43.6 million of depreciation, depletion and amortization expense in 2002 was a result of increasing sales volumes and an increased rate from $1.11 per Mcfe in 2001 to $1.24 per Mcfe in 2002.

Exploration Costs. Exploration costs increased $1.0 million to $1.8 million for 2002 compared with $0.8 million for 2001. The increase was partially the result of a $420,000 charge for an exploratory dry hole in 2002. The remaining increase in 2002 is related to the further development and processing of our geophysical library.

General and Administrative Expenses. General and administrative expenses increased 9.5% or $1.1 million from $10.9 million in 2001 to $12.0 million in 2002. This increase was related to increases in compensation expense associated with increased personnel required to administer our growth and to general cost inflation.

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Interest Expense. Interest expense increased $0.7 million to $10.9 million in 2002 compared to $10.2 million in 2001. The increase was due to higher average debt levels in 2002 to fund our growth, partially offset by a lower effective interest rate.

Income Tax Expense. Our effective tax rate before tax credits was 36.8% in 2002 and 36.2% in 2001. In 2001, we were able to reduce our tax expense by $6.6 million due to the recording of Section 29 tax credits. In 2002, we generated $5.4 million of Section 29 credits that we were not able to offset against tax expense. Under our tax separation and indemnification agreement with Alliant Energy, we expect to be compensated for these credits in the future when they are utilized by Alliant Energy. Under generally accepted accounting principles, the recording of the tax credits in 2002 were required to be charged as additional paid-in capital rather than as a decrease to our 2002 income tax expense. Section 29 tax credit provisions of the Internal Revenue Code expired December 31, 2002. Therefore, unless additional legislation is passed, Section 29 credits will not be available in periods subsequent to 2002.

Net Income. Net income decreased from $41.2 million in 2001 to $7.7 million in 2002. The primary reasons were a $19.0 million decline in revenues, a $23.5 million increase in expenses and the inability to recognize $5.4 million of tax credits as a reduction of tax expense. The revenue decrease was caused by a decline in oil and natural gas prices between years and $10.7 million less gains from the sales of properties in 2002. The expense increase was caused by the $9.0 million reduction to 2001 depreciation, depletion and amortization related to the adjustment of the Point Arguello abandonment liability and cost increases in all other categories to operate and administer the property acquisitions during 2001 and 2002.

Liquidity and Capital Resources

Cash Flows. During the year ended December 31, 2003, we generated $96.4 million from operating activities and received $4.6 million in contributions from Alliant Energy. We used a portion of these cash proceeds to fund $52.0 million of capital expenditures. We entered 2004 with $53.6 million of cash and cash equivalents. During the first quarter of 2004, we generated an additional $27.3 million from operating activities before consideration of working capital changes. 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. The decrease in total assets between December 31, 2003 and March 31, 2004 was primarily the result of the debt repayment. At March 31, 2004, our debt to total capitalization ratio was 35%, we had $16.4 million of cash on hand, $28.4 million of working capital and $271.3 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 $68.0 million during 2004, an increase from the $48.6 million spent on capitalized development during 2003. During the first quarter of 2004, we spent $11.5 million on development, which was an increase from the $5.2 million spent on development during the first quarter of 2003. 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 $68.0 million, we could finance the additional capital expenditures with cash on hand, operating cash flow, additional borrowings under Whiting Oil and Gas Corporation’s credit agreement, issuances of additional equity or development with industry partners. The 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. Whiting Oil and Gas Corporation has a $350.0 million credit agreement with a syndicate of banks. At March 31, 2004, our borrowing base was $210.0 million with an outstanding principal balance of $145.0 million. The borrowing base under the credit agreement is based on the collateral value of our proved reserves and is subject to redetermination on May 1 and November 1 of each year. The borrowing base of $210

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million was reaffirmed on May 1, 2004; however, the borrowing base was reduced to $195.0 million on May 11, 2004 upon completion of our private placement of our 7.25% senior subordinated notes due 2012. The credit agreement provides for interest only payments until December 20, 2005, when the entire amount borrowed is due. 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 0.25% to 1.0% depending on the utilization percentage of the borrowing base, or (2) at the LIBOR rate plus a margin where the margin varies from 1.5% to 2.25% 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. Based on our borrowing base utilization percentage at March 31, 2004, the LIBOR margin was 1.75%. Commitment fees of 0.375% to 0.5% 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, 2004, all amounts outstanding under the credit agreement accrued interest at an annual rate of 2.95% fixed through August 6, 2004

The credit agreement has covenants that restrict the payment of cash dividends, borrowings, sale of assets, loans to others, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders and requires us to maintain certain debt to EBITDAX (as defined in the credit agreement) ratios and a working capital ratio. In particular, while the credit agreement allows our subsidiaries to make payments to us so that we may pay interest on the old notes and the new notes, it does not allow our subsidiaries to make payments to us to pay principal on the old notes or the new notes. We were in compliance with our covenants under the credit agreement as of March 31, 2004. The credit agreement is secured by a first lien on substantially all of Whiting Oil and Gas Corporation’s assets. Whiting Petroleum Corporation has guaranteed the obligations of Whiting Oil and Gas Corporation under the credit agreement.

If our acquisition of Equity Oil Company closes, then Whiting Oil and Gas Corporation expects to incorporate into its credit agreement Equity’s outstanding debt under its credit facility, which was $29.0 million as of December 31, 2003. See “—Acquisition of Equity Oil Company.”

On June 3, 2004, we entered into an amended and restated credit agreement with the lenders under Whiting Oil and Gas Corporation’s credit agreement to (1) permit the incorporation of Equity Oil Company’s debt under its existing credit facility into Whiting Oil and Gas Corporation’s credit agreement, (2) reaffirm our $195.0 million borrowing base, (3) increase the lenders’ total commitment under the credit agreement to $400.0 million and (4) extend the maturity of the credit agreement to June 2008.

7.25% Senior Subordinated Notes due 2012. On May 11, 2004, we issued, in a private placement, $150,000,000 aggregate principal amount of our 7.25% 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 are unsecured obligations of ours and are subordinated to all of our senior debt. The indenture governing the notes contains various restrictive covenants that may limit our and our subsidiaries’ ability to, among other things, (1) pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our subordinated debt; (2) make investments; (3) incur additional indebtedness or issue preferred stock; (4) sell assets; (5) consolidate, merge or transfer all or substantially all of the assets of us and our restricted subsidiaries taken as a whole and (6) enter into hedging contracts. These covenants may limit the discretion of our management in operating our business. Two of our subsidiaries, Whiting Oil and Gas Corporation and Whiting Programs, Inc., have fully, unconditionally, jointly and severally guaranteed our obligations under the notes.

Historical Financing. Prior to our initial public offering in November 2003, we functioned as an indirect wholly-owned subsidiary of Alliant Energy. As a result, our liquidity was directly related to the financial resources and capital expenditure allocations of Alliant Energy. In the past, Alliant Energy provided a capital expenditure budget and funded net cash requirements beyond cash generated from operations. Until our $185.0

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million bank borrowing in December 2002, we did not rely on outside sources of borrowing or capital. Instead, we received advances on Alliant Energy’s intercompany credit facility, which primarily covered the shortfall between our capital expenditures (including acquisitions) and cash generated from operations and property sales. The table below describes net borrowings and payments on Alliant Energy’s intercompany credit facility.


	Year Ended December 31,
	2003			2002			2001		Total
	(dollars in millions)
Alliant Energy⁽¹⁾	$	(80.9	)	$	(83.1	)	$	23.9	$	(140.1	)
Whiting Oil and Gas Corporation credit agreement		—			185.0			—		185.0

Total	$	(80.9	)	$	101.9		$	23.9	$	44.9

⁽¹⁾	In March 2003, Alliant Energy converted its remaining intercompany loan plus accrued interest of $80.9 million to our equity.

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.

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.

Schedule of Contractual Obligations. The following table summarizes our obligations and commitments as of December 31, 2003 to make future payments under certain contracts, aggregated by category of contractual obligation, for specified time periods.


	Payments due by period
Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-Term Debt	$	188.0		—	$	188.0		—		—
Operating Leases		2.0	$	1.1		0.9		—		—
Tax Separation and Indemnification Agreement with Alliant Energy⁽¹⁾		28.8		—		4.2	$	3.1	$	21.5

Total	$	218.8	$	1.1	$	193.1	$	3.1	$	21.5

⁽¹⁾	Amounts shown are estimates based on estimated future income tax benefits from the increase in tax basis described under “Tax Separation and Indemnification Agreement with Alliant Energy” above.

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Off-Balance Sheet Arrangements. 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, 2004 increased to 50% of the actual price received in excess of $19.77 per barrel. Currently, approximately 46,000 net barrels of crude oil per month (21% of December 2003 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. As of December 31, 2003, we have paid $3.1 million under this agreement and we have accrued an additional $215,000 as currently payable.

New Accounting Policies

In June 2001, the Financial Accounting Standards Board, or the FASB, issued SFAS No. 141, “Business Combinations,” which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets,” which discontinues the practice of amortizing goodwill and indefinite-lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. We did not change or reclassify the contractual mineral rights included in our oil and natural gas properties on the balance sheet upon adoption of SFAS No. 142. We believe that the current accounting of such mineral rights as part of crude oil and natural gas properties is appropriate under the successful efforts method of accounting. However, there is an alternative view that reclassification of mineral rights to an intangible asset may be necessary. If a reclassification of contractual mineral rights acquired subsequent to July 1, 2001 from oil and gas properties to long term intangible assets is required, then the reclassified amounts would be approximately $48.7 million as of December 31, 2001, $161.2 million as of December 31, 2002 and $160.1 million as of December 31, 2003. We do not believe that the ultimate outcome of this issue will have a significant impact on our cash flows, results of operations or financial condition.

The FASB is currently evaluating the application of certain provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive industries, including oil and natural gas. The FASB is considering whether the provisions of SFAS No. 141 and SFAS No. 142 require registrants to classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other oil and gas property costs, and provide specific footnote disclosures. In the event the FASB determines that costs associated with mineral rights are required to be classified as intangible assets, we currently believe that our financial condition and results of operations would not be affected.

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 that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 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. In regards to us, this statement applies directly to the plug and abandonment liabilities associated with our 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 is accreted at the end of each accounting period through charges to accretion expense. The liability is discounted using a credit-adjusted risk-free rate of approximately 7%. If the obligation is settled for other than the carrying amount, a gain or loss is recognized on settlement. Upon adoption of SFAS No. 143, we recorded an increase to our discounted abandonment liability 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). We have an additional $4.3 million abandonment liability relating to our retained obligation with respect to the Point Arguello facility located offshore from California.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associates with Exit or Disposal Activities.” This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (“EITF”) Issue No. 94-3, “Liability Recognition for Certain

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Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. The adoption of this Statement had no impact on our financial statements.

FASB Interpretation No. 45, or FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” was issued in November 2002 by the FASB. FIN 45 requires a guarantor to recognize a liability for the fair value of the obligation it assumes under certain guarantees. Additionally, FIN 45 requires a guarantor to disclose certain aspects of each guarantee, or each group of similar guarantees, including the nature of the guarantee, the maximum exposure under the guarantee, the current carrying amount of any liability for the guarantee, and any recourse provisions allowing the guarantor to recover from third parties any amounts paid under the guarantee. The disclosure provisions of FIN 45 are effective for financial statements for both interim and annual periods ending after December 15, 2002. The fair value measurement provisions of FIN 45 are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The adoption of this statement did not have a material impact on our financial statements.

In January 2003, the FASB issued FASB Interpretation No. 46, or FIN 46 (as revised in December 2003), “Consolidation of Variable Interest Entities.” FIN 46 clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated support from other parties. FIN 46 requires existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. All companies with interests in variable interest entities created after January 31, 2003, shall apply the provisions of FIN 46 to those entities immediately. The adoption of this Statement had no impact on our financial statements.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” to amend and clarify financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. The changes in this statement require that contracts with comparable characteristics be accounted for similarly to achieve more consistent reporting of contracts as either derivative or hybrid instruments. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003 and will be applied prospectively. The adoption of this Statement had no impact on our financial statements.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” to classify certain financial instruments as liabilities in statements of financial position. The financial instruments are mandatorily redeemable shares, which the issuing company is obligated to buy back in exchange for cash or other assets, put options and forward purchase contracts, instruments that do or may require the issuer to buy back some of its shares in exchange for cash or other assets, and obligations that can be settled with shares, the monetary value of which is fixed, tied solely or predominantly to a variable such as a market index, or varies inversely with the value of the issuers’ shares. Most of the guidance in SFAS No. 150 is effective for all financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this Statement had no impact on our financial statements.

Critical Accounting Policies and Estimates

Our discussion of financial condition and results of operation is based upon the information reported in our consolidated financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on

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historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. Our significant accounting policies are detailed in Note 1 to our consolidated financial statements. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.

Revenue Recognition. We predominantly derive our revenue from the sale of produced crude oil and natural gas. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received; however, differences have been insignificant.

Hedging. Our crude oil and natural gas hedges are designed to be treated as cash flow hedges under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activity.” This policy is significant since it impacts the timing of revenue recognition. Under this pronouncement, the majority of our hedging gains or losses are recorded in the month the contracts settle. We reflect this as an adjustment to revenue through the “Gain (loss) on oil and gas hedging activities” line item in our consolidated income statements. If our hedges did not qualify for cash flow hedge treatment, then our consolidated income statements could include large non-cash fluctuations in this line item, particularly in volatile pricing environments, as our contracts are marked to their period end market values.

Successful Efforts Accounting. We account for our oil and natural gas operations using the successful efforts method of accounting. Under this method, all costs associated with property acquisition, successful exploratory wells and all development wells are capitalized. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells and oil and natural gas production costs. All of our properties are located within the continental United States and the Gulf of Mexico.

Oil and Natural Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this prospectus are prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of:

•

the quality and quantity of available data;

•

the interpretation of that data;

•

the accuracy of various mandated economic assumptions; and

•

the judgments of the persons preparing the estimates.

Our proved reserve information included in this prospectus is based on estimates prepared by Ryder Scott Company, Cawley, Gillespie & Associates, Inc. and R.A. Lenser & Associates, Inc., each independent petroleum engineers, and Whiting Oil and Gas Corporation’s engineering staff. The independent petroleum engineers evaluated approximately 83% of the pre-tax PV10% value of our proved reserves and Whiting Oil and Gas Corporation’s engineering staff evaluated the remainder. Estimates prepared by others may be higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. We continually make revisions to reserve estimates throughout the year as additional information becomes available. We make changes to depletion rates and impairment calculations in the same period that changes to the reserve estimates are made.

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Impairment of Oil and Natural Gas Properties. We review the value of our oil and natural gas properties whenever management judges that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. We provide for impairments on undeveloped property when we determine that the property will not be developed or a permanent impairment in value has occurred. Impairments of proved producing properties are calculated by comparing future net undiscounted cash flows on a field- by-field basis using escalated prices to the net recorded book cost at the end of each period. If the net capitalized cost exceeds net future cash flows, the cost of the property is written down to “fair value,” which is determined using net discounted future cash flows from the producing property. Different pricing assumptions or discount rates could result in a different calculated impairment. We have not recorded any property impairments since 1999.

Income Taxes. We provide for income taxes in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes.” Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to actual in the period we file our tax returns.

Effects of Inflation and Pricing

We experienced increased costs during 2001, 2002 and 2003 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.

Acquisition of Equity Oil Company

On February 2, 2004, we announced that we entered into a definitive merger agreement to acquire Equity Oil Company. The merger agreement provides for a stock-for-stock merger under which Equity shareholders will receive a fixed exchange ratio of 0.185 shares of our common stock for each share of Equity common stock that they own. In addition, Whiting Oil and Gas Corporation expects to incorporate into its credit agreement the debt outstanding under Equity’s credit facility, which was approximately $29.0 million as of March 31, 2004. The merger is subject to the approval of shareholders owning two-thirds of the outstanding Equity shares and other customary closing conditions. Equity intends to call a special meeting of its shareholders during the second quarter of 2004 to consider and vote on the merger. We expect to complete the merger as soon as practicable following approval by Equity’s shareholders.

Quantitative and Qualitative Disclosure About Market Risk

Commodity Price Risk

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Based on December 2003 production, our income before income taxes moves approximately $2.1 million for every $0.10 change in natural gas prices and approximately $2.4 million for each $1.00 change in crude oil prices.

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We periodically enter into derivative contracts to manage our exposure to oil and natural gas price volatility. Our derivative contracts have traditionally been with no-cost collars, although we evaluate other forms of derivative instruments as well. Our derivative contracts have historically qualified for cash flow hedge accounting under SFAS No. 133. This accounting treatment allows the aggregate change in fair market value to be recorded as other comprehensive income on the consolidated balance sheet. Recognition in the consolidated income statement occurs in the period of contract settlement. We generally limit our aggregate hedge position to less than 50% of expected production, but may hedge larger percentages of total expected production in certain circumstances. We do not intend to hedge in excess of 60% of our expected production. We also seek to diversify our hedge position with various counterparties where we have clear indications of their current financial strength.

Our outstanding hedges at May 26, 2004 are summarized below:


Commodity	Period	Monthly Volume (MMbtu)/(Bbl)	NYMEX Floor/Ceiling
Natural Gas	07/2004 to 09/2004	400,000	$	4.50/$8.35
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
Crude Oil	04/2004 to 06/2004	50,000	$	28.00/$35.40
Crude Oil	04/2004 to 06/2004	50,000	$	28.00/$37.94
Crude Oil	07/2004 to 09/2004	50,000	$	28.00/$35.37
Crude Oil	07/2004 to 09/2004	50,000	$	30.00/$38.78
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

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 $360,000 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 $900,000 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 May 1, 2004 are summarized below:


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

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


Hedges and Contracts Summary	Hedged and Contracted (Mmbtu)/(Bbl) per Month	As a Percentage of 2003 Avg. Monthly Production (Gas/Oil)
April–June 2004	111,000 /100,000	6.1% /46.3%
July–September 2004	511,000 /100,000	28.4% /46.3%
October–December 2004	911,000 /100,000	50.6% /46.3%
2005 and thereafter	111,000 / —	6.1% / —

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Interest Rate Risk

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 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 March 31, 2003, the interest rate on the entire outstanding principal balance under our credit facility was fixed at 2.95% through August 6, 2004. At March 31, 2003, the carrying amount approximated fair market value. Assuming a constant debt level of $145.0 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 $584,000.

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BUSINESS AND PROPERTIES

About Our Company

The following table summarizes our total net proved reserves and pre-tax PV10% value within our four core areas as of January 1, 2004, as well as our December 2003 average daily production.


	Oil (MMbbl)	Proved Reserves	Total (Bcfe)	Pre-Tax PV 10% Value (In thousands)		December 2003 Average Daily Production
Core Area	Oil (MMbbl)	Natural Gas (Bcf)	Total (Bcfe)	Pre-Tax PV 10% Value (In thousands)		MMcfe	% Natural Gas
Gulf Coast/Permian Basin	5.5	89.4	122.5	$	266,745	40.0	76	%
Rocky Mountains	26.5	17.6	176.5		261,071	32.3	11	%
Michigan	1.1	107.2	114.1		214,407	21.3	92	%
Mid-Continent	1.5	16.8	25.7		42,400	8.2	73	%
Total	34.6	231.0	438.8	$	784,623	101.8	59	%

Business Strategy

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During the three years ended December 31, 2003, we invested $94 million to participate in the drilling of 169 gross (60.6 net) wells. The majority of these wells were developmental wells, and 85.2% were successful completions. As of January 1, 2004, we had identified a total of 171 proved undeveloped drilling locations on our properties. We drilled or participated in the drilling of 72 gross (24.8 net) wells during the year ended December 31, 2003. We plan to invest $68 million on the further development of our properties in 2004.

Competitive Strengths

We believe that our key competitive strengths lie in our diversified asset base, our experienced management team and our commitment to efficient utilization of new technologies.

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Proved Reserves

Our proved reserves as of January 1, 2004 are summarized in the table below.


	Oil (MMbl)	Natural Gas (MMcf)	Total (Bcfe)	% of Total Proved		Pre-tax PV 10% (In thousands)		Future Capital Expenditures (In thousands)
Gulf Coast/Permian Basin:
PDP	4,300	52,322	78.1	17.8	%	$	172,347	$	2,784
PDNP	287	6,232	8.0	1.8	%		20,465		1,141
PUD	939	30,856	36.4	8.3	%		73,933		25,794

Total Proved	5,526	89,410	122.5	27.9	%	$	266,745	$	29,719

Rocky Mountains:
PDP	18,898	13,183	126.6	28.8	%	$	169,051	$	743
PDNP	571	205	3.6	0.8	%		4,340		393
PUD	7,008	4,257	46.3	10.6	%		87,680		18,774

Total Proved	26,477	17,645	176.5	40.2	%	$	261,071	$	19,910

Michigan:
PDP	469	76,263	79.1	18.0	%	$	133,618	$	0
PDNP	140	6,914	7.8	1.8	%		23,854		1,713
PUD	536	24,017	27.2	6.2	%		56,935		14,755

Total Proved	1,145	107,194	114.1	26.0	%	$	214,407	$	16,468

Mid-Continent:
PDP	1,438	15,900	24.5	5.6	%	$	41,271	$	0
PDNP	53	863	1.2	0.3	%		1,129		229

Total Proved	1,491	16,763	25.7	5.9	%	$	42,400	$	229

Total Corporate:
PDP	25,105	157,668	308.3	70.2	%	$	516,287	$	3,527
PDNP	1,051	14,214	20.6	4.7	%		49,788		3,476
PUD	8,483	59,130	109.9	25.1	%		218,548		59,323

Total Proved	34,639	231,012	438.8	100.0	%	$	784,623	$	66,326

Summary of Oil and Natural Gas Properties and Projects

Gulf Coast/Permian Basin Region

Our Gulf Coast/Permian Basin operations include assets in Texas, Louisiana, Alabama and New Mexico. The Gulf Coast/Permian Basin region contributes 122.5 Bcfe (73% natural gas) of net proved reserves to our portfolio of operations, which represents 27.9% of our total net proved reserves. Approximately 90.9% of the proved reserves of our Gulf Coast/Permian Basin operations are related to properties in Texas.

Stuart City Reef Trend. We have leasehold interests in five fields located along a regional geologic structure known as the Stuart City Reef Trend in south-central Texas, where we are employing horizontal drilling technologies to develop gas reserves in the Edwards Limestone at 14,000 feet. Our Stuart City properties contain 35.5 Bcfe of net proved reserves primarily within the Word North field, the Yoakum field and the Kawitt field. During 2003, we drilled three successful Edwards wells in these fields. We plan to continue development of our Edwards gas reserves by drilling a combination of new horizontal wells and casing-exit horizontal wells. We have also begun an active drilling program targeting the Wilcox Formation at 10,000 feet. During 2003, we drilled one Wilcox well and plan additional drilling in the Kawitt and Word North fields.

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Vicksburg Trend. We own interests in several fields within the Vicksburg Trend located in the vicinity of Nueces Bay in San Patricio and Nueces Counties, Texas. These fields include the Agua Dulce, Triple A, South Midway, and East White Point fields. Natural gas and oil production in this area is from multiple, low permeability sandstone reservoirs within the Vicksburg and Frio Formations at depths ranging between 4,000 and 15,000 feet.

In the Agua Dulce field, we operate 13 wells with a 99.0% average working interest. Our properties in this field contain 17.7 Bcfe of net proved reserves. We have begun an active development program at Agua Dulce where we are employing 3-D seismic to exploit multiple, low permeability gas sands within a highly faulted anticline. During 2003 we drilled one successful gas well, but had mechanical difficulties in completing a second well and are currently sidetracking the wellbore. We plan to continue the development of our gas reserves through the acquisition of additional seismic data and new drilling.

Gulf of Mexico. In South Timbalier Block 185, we have an 18% working interest in a successful, non-operated drilling and recompletion project in of the Gulf of Mexico shelf area, offshore Louisiana. We also have interests in ongoing drilling activity in South Timbalier, Blocks 185, 200 and 203, which we expect to continue during 2004.

Cotton Valley Reef Trend. We are involved in an exploration play along the Cotton Valley Reef trend primarily in Leon and Robertson counties, Texas. Fields along this trend produce gas from pinnacle reefs within the Cotton Valley formation at 14,000 feet. We are employing modern seismic processing techniques to accurately delineate these reservoirs. We are currently drilling one of these wells and plan one additional well in 2004.

Rocky Mountain Region

Our Rocky Mountain operations include assets in North Dakota, Montana, Colorado and Wyoming. As of January 1, 2004, our proved reserves in the Rocky Mountain region were 29.4 MMboe (90% oil), which accounted for 40.2% of our total proved reserves. The majority of our interests in the Rocky Mountain region are within North Dakota and Montana, where we have interests in 97 fields, 45 of which we operate. Approximately 87% of the proved reserves of our Rocky Mountain operations are related to assets in North Dakota.

Big Stick (Madison) Unit. The Big Stick field, which contains the Big Stick (Madison) Unit, is located in Billings County, North Dakota and produces from a series of stacked, oil saturated, porous dolomites within the Mission Canyon Formation at an average depth of 9,400 feet. We operate this unit and own a 62% working interest. Our net recoverable reserves at Big Stick at year end were 12.6 MMboe. Since acquiring this property, we have increased unit oil production by 14% through a combination of workovers and sidetracks of existing wells as well as new drilling. During the past year, we have been engaged in a detailed reservoir modeling study to determine the benefits and feasibility of implementing a waterflood within the unit. We are also developing our deeper, non-unitized interests at Big Stick, and recently drilled a new well which identified gas pay in the Red River Formation at 12,700 feet and oil pay in the Duperow Formation at 11,000 feet.

North Elkhorn Ranch Unit. The North Elkhorn Ranch Unit is located eight miles north of the Big Stick field in Billings County, North Dakota and also produces from reservoirs within the Mission Canyon Formation. We hold a 60% working interest and operate this unit. Our net recoverable reserves are 4.5 MMboe. Since assuming unit operations in May of 2002, we have reversed the decline in unit production, primarily through workovers of existing wells and reduction in downtime. We drilled one unit well late in 2003 and plan additional development drilling during 2004.

Red Water Field. We have a 40% non-operated working interest in an active exploration and development play which targets the middle member of the Mississippian Bakken Formation in Richland County, Montana. During 2003 we drilled four new horizontal wells which have estimated ultimate recoveries of 500 to 800 Mboe per well. At year end, our net recoverable reserves from the Red Water Field were 1.2 MMboe.

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Sioux Field. We have a 65% working interest and operate this field which is located in McKenzie County, North Dakota. This field produces oil and gas from multiple zones at depths up to 13,700 feet. Since acquiring this property in 2002, we have increased production by 130% primarily through new drilling and recompletions. In 2003, we drilled a successful well with up to eight producing zones. Initially, production will be from the Interlake Formation which has tested oil at approximately 250 barrels of oil per day.

Michigan Region

Our Michigan operations include assets in Michigan and Ohio. Virtually all of the proved reserves and pre-tax PV10% value associated with our Michigan operations are from properties located in the State of Michigan. The Michigan region contributes 114.1 Bcfe (94% natural gas) of net proved reserves to our portfolio of operations, which represents 26% of our total net proved reserves.

The majority of our Michigan production is from a non-conventional natural gas reservoir in the northern Michigan basin known as the Antrim Shale. The remainder of our production is from a variety of conventional oil and natural gas reservoirs in the eastern and southern portions of the basin. We operate the majority of our non-Antrim production as well as the West Branch and Stoney Point natural gas plants, while the majority of our Antrim production is operated by local companies in close cooperation with our technical staff.

Antrim Production. Natural gas is produced from fractures within the Antrim Shale at depths from 1,200 to 2,200 feet. The productive fairway of the Antrim is widespread across northern Michigan, covering a 3,400 square mile region. We own interests in 57 multi-well Antrim Shale natural gas projects within this area. As of January 1, 2004, our net proved reserves from these projects were 79.6 Bcfe (100% natural gas).

Approximately 10 of our Antrim Shale projects have significant remaining development potential. These projects are concentrated in three areas. In Briley Township, we have proved undeveloped reserves of 5.9 Bcf. The Old Vandy Projects in Charlevoix and Otsego Counties have proved undeveloped reserves of 2.0 Bcf. An additional 4.9 Bcf of proved undeveloped reserves are present within eight additional townships which are less geographically concentrated. During 2003, we drilled 15 wells, and we expect to drill 20 wells during 2004.

Conventional (non-Antrim) Production. Our non-Antrim Shale production is from conventional reservoirs (primarily the Prairie du Chien, Trenton and Black River Formations) located in Central Michigan. Estimated net proved reserves from these properties total 34.5 Bcfe (80% natural gas). We have interests in 20 oil and natural gas fields in this region and operate 7 of them.

The Prairie du Chien fields produce natural gas and retrograde condensate from various intervals within a 500 to 800 foot thick sequence of sandstones and dolomitic sandstones at a depth of 10,500 to 11,200 feet. The low permeability and heterogeneous character of the Prairie du Chien reservoirs has resulted in low recovery of the original natural gas in place from the existing wells, providing us with significant opportunities for increased recovery through infill and horizontal drilling.

Our undeveloped potential resides in three fields, West Branch, Clayton and South Buckeye. All are structurally trapped hydrocarbon accumulations and to date recoveries range from 4% to 37% of the in place hydrocarbons. Our undeveloped proved reserve potential in these three fields is estimated at 14.4 Bcfe versus 60 Bcfe produced to date. Two locations have been identified for drilling in 2004. We believe that significant additional potential exists for horizontal re-entry wells and conventional vertical and horizontal wells.

Mid-Continent Region

Our Mid-Continent operations include assets in Oklahoma, Arkansas and Kansas. The Mid-Continent region contributes 25.7 Bcfe (65% natural gas) of net proved reserves to our portfolio of operations, which represents 5.9% of total net proved reserves. The majority of the proved value within our Mid-Continent operations is

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related to properties in Oklahoma. The Oklahoma production is scattered throughout the state, with the single largest concentration being in the company-operated Putnam Oswego Unit, located in Dewey and Custer Counties in West-Central Oklahoma.

Our proved properties located in Arkansas are operated, and are primarily in two fields, the Magnolia Smackover Pool Unit and the Wesson Hogg Sand Unit. Both of these fields are mature pressure maintenance units.

Cherokee Basin Coalbed Methane Project. In 2002 and 2003, we acquired a 91,284 acre lease position in the Cherokee Basin, which is prospective for natural gas from coal seams (coalbed methane). Approximately 70,000 acres are concentrated in our Center prospect, which is located south of Emporia, Kansas and in which we have a 100% working interest. Eight stratigraphic test wells were drilled during 2003 and evaluation efforts are ongoing.

Acreage

The following table summarizes gross and net developed and undeveloped acreage at December 31, 2003 by region (net acreage is our percentage ownership of gross acreage). Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.


	Developed Acreage		Undeveloped Acreage		Total Acreage
	Gross	Net	Gross	Net	Gross	Net
Gulf Coast/Permian Basin	159,603	58,813	8,514	7,518	168,117	66,331
Rocky Mountains	137,038	66,507	286,000	90,400	423,038	156,907
Michigan	179,141	59,000	—	—	179,141	59,000
Mid-Continent	40,740	21,438	91,284	90,395	132,024	111,833

Total	516,522	205,758	385,798	188,313	902,320	394,071

Production History

The following table presents the historical information about our produced natural gas and oil volumes.


	Year Ended December 31,
	2003		2002		2001
Oil production (MMbbls)		2.6		2.3		2.1
Natural gas production (Bcf)		21.6		21.4		19.8
Total production (Bcfe)		37.2		35.2		32.4
Daily production (MMcfe/d)		101.8		96.4		88.8
Average sales prices:
Natural gas (per Mcf)⁽¹⁾	$	4.78	$	3.21	$	3.82
Oil (per Bbl)(1)		27.50		23.35		23.85
Total (per Mcfe)⁽¹⁾		4.73		3.48		3.88
Costs and expenses (per Mcfe):
Lease operating expenses	$	1.16	$	0.93	$	0.92
Production taxes		0.29		0.21		0.20
Depreciation, depletion and amortization expense		1.11		1.24		1.11
General and administrative expenses, net of reimbursements		0.34		0.34		0.34

⁽¹⁾	Before consideration of hedging transactions.

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Productive Wells

The following table presents our ownership at December 31, 2003 in productive oil and natural gas wells by region (a net well is our percentage ownership of a gross well).


	Oil Wells		Natural Gas Wells		Total Wells
	Gross	Net	Gross	Net	Gross	Net
Gulf Coast/Permian Basin	1,571	139.7	852	282.0	2,423	421.7
Rocky Mountains	863	254.7	115	17.9	978	272.6
Michigan	78	57.0	968	368.3	1,046	425.3
Mid-Continent	372	151.2	187	78.8	559	230.0

Total	2,884	602.6	2,122	747.0	5,006	1,349.6

Drilling Activity

We are engaged in numerous drilling activities on properties presently owned and intend to drill or develop other properties acquired in the future. The following table sets forth the results of our drilling activity for the last three years. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.


	Gulf Coast/ Permian Basin			Mid-Continent			Rocky Mountains			Michigan		Total
	2003	2002	2001	2003	2002	2001	2003	2002	2001	2003	2002	2003	2002	2001
Gross:
Productive	22	10	22	2	3	3	25	7	31	15	4	64	24	56
Dry	3	6	6	—	—	—	5	3	2	—	—	8	9	8

Total	25	16	28	2	3	3	30	10	33	15	4	72	33	64

Net:
Productive	10.6	4.2	10.5	0.1	0.2	1.0	7.4	2.7	8.1	2.8	1.0	20.9	8.1	19.6
Dry	.9	2.2	1.9	—	—	—	3.0	2.1	1.9	—	—	3.9	4.3	3.8

Total	11.5	6.4	12.4	0.1	0.2	1.0	10.4	4.8	10.0	2.8	1.0	24.8	12.4	23.4

Our drilling activity from exploratory wells, which are included in the above table, include one productive gross well (0.2 net) in 2001 in the Gulf Coast/Permian Basin region, one dry gross well (0.15 net) in 2002 in the Gulf Coast/Permian Basin region, three dry gross wells (1.55 net) in 2003, two of which were located in the Rocky Mountain region and one in the Gulf Coast/Permian Basin region.

Marketing and Major Customers

We principally sell our oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is trucked to storage facilities. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For fiscal year 2003, no single customer was responsible for generating 10% or more of our total oil and natural gas sales.

Title to Properties

Our properties are subject to customary royalty interests, liens under indebtedness, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and

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restrictions. Whiting Oil and Gas Corporation’s credit agreement is also secured by a first lien on substantially all of our assets. We do not believe that any of these burdens materially interferes with the use of our properties in the operation of our business.

We believe that we have satisfactory title to or rights in all of our producing properties. As is customary in the oil and natural gas industry, minimal investigation of title is made at the time of acquisition of undeveloped properties. In most cases, we investigate title and obtain title opinions from counsel only when we acquire producing properties or before commencement of drilling operations.

Competition

Regulation

Regulation of Transportation and Sale of Natural Gas

Historically, the transportation and sale for resale of natural gas in inter state commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the Federal Energy Regulatory Commission, or the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act. The Decontrol Act removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued Order No. 636 and a series of related orders to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised the FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect. While most major aspects of Order No. 637 have been upheld on judicial review, certain issues such as capacity segmentation and

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right of first refusal are pending further consideration by the FERC. We cannot predict what action FERC will take on these matters in the future, or whether the FERC’s actions will survive further judicial review.

The Outer Continental Shelf Lands Act, which the FERC implements as to transportation and pipeline issues, requires that all pipelines operating on or across the outer continental shelf provide open access, non-discriminatory transportation service. One of the FERC’s principal goals in carrying out this Act’s mandate is to increase transparency in the market to provide producers and shippers on the outer continental shelf with greater assurance of open access services on pipelines located on the outer continental shelf and non-discriminatory rates and conditions of service on such pipelines.

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before the FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.

Regulation of Transportation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

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Regulation of Production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Some of our offshore operations are conducted on federal leases that are administered by Minerals Management Service, or MMS, and are required to comply with the regulations and orders issued by MMS under the Outer Continental Shelf Lands Act. Among other things, we are required to obtain prior MMS approval for any exploration plans we pursue and our development and production plans for these leases. MMS regulations also establish construction requirements for production facilities located on our federal offshore leases and govern the plugging and abandonment of wells and the removal of production facilities from these leases. Under limited circumstances, MMS could require us to suspend or terminate our operations on a federal lease.

MMS also establishes the basis for royalty payments due under federal oil and natural gas leases through regulations issued under applicable statutory authority. State regulatory authorities establish similar standards for royalty payments due under state oil and natural gas leases. The basis for royalty payments established by MMS and the state regulatory authorities is generally applicable to all federal and state oil and natural gas lessees. Accordingly, we believe that the impact of royalty regulation on our operations should generally be the same as the impact on our competitors.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental Regulations

General. Our oil and natural gas exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, also referred to as the “EPA,” issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various materials that can be released into the environment in connection with drilling and production activities, limit or prohibit project siting, construction, or drilling activities on certain lands laying within wilderness, wetlands, ecologically sensitive and other protected areas, require remedial action to prevent pollution from former operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations. The EPA and analogous state agencies may delay or refuse the issuance of required permits or otherwise include onerous or limiting permit conditions that may have a significant adverse impact on our ability to conduct operations. The regulatory burden on the oil and natural gas industry increases the cost of doing business and consequently affects its profitability.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly material handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and natural gas industry in

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general. While we believe that we are in substantial compliance with current applicable environmental laws and regulations and have not experienced any material adverse effect from compliance with these environmental requirements, there is no assurance that this trend will continue in the future.

The environmental laws and regulations which have the most significant impact on the oil and natural gas exploration and production industry are as follows:

Superfund. The Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the “owner” or “operator” of a disposal site or sites where a release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, such persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our ordinary operations, we may generate material that may fall within CERCLA’s definition of a “hazardous substance.” Consequently, we may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these materials have been disposed or released.

We currently own or lease, and in the past have owned or leased, properties that for many years have been used for the exploration and production of oil and natural gas. Although we and our predecessors have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other materials may have been disposed or released on, under, or from the properties owned or leased by us or on, under, or from other locations where these hydrocarbons and materials have been taken for disposal. In addition, many of these owned and leased properties have been operated by third parties whose management and disposal of hydrocarbons and materials were not under our control. Similarly, the disposal facilities where discarded materials are sent are also often operated by third parties whose waste treatment and disposal practices may not be adequate. While we only use what we consider to be reputable disposal facilities, we might not know of a potential problem if the disposal occurred before we acquired the property. Our properties, adjacent affected properties, the disposal sites, and the material itself may be subject to CERCLA and analogous state laws. Under these laws, we could be required:

•

to remove or remediate previously disposed materials, including materials disposed or released by prior owners or operators or other third parties;

•

to clean up contaminated property, including contaminated groundwater; or

•

to perform remedial operations to prevent future contamination, including the plugging and abandonment of wells drilled and left inactive by prior owners and operators.

At this time, we do not believe that we are a potentially responsible party with respect to any Superfund site and we have not been notified of any claim, liability or damages under CERCLA.

Oil Pollution Act. The Oil Pollution Act of 1990, also known as “OPA,” and regulations issued under OPA impose strict, joint and several liability on “responsible parties” for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located. The OPA establishes a liability limit for onshore facilities of $350 million while the liability limit for offshore facilities is the payment of all removal costs plus up to $75 million in other damages but these limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a cleanup. The OPA also requires the lessee or permittee of the offshore area in which a

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covered offshore facility is located to establish and maintain evidence of financial responsibility in the amount of $35 million ($10 million if the offshore facility is located landward of the seaward boundary of a state) to cover liabilities related to an oil spill for which such person is statutorily responsible. The amount of financial responsibility required under OPA may be increased up to $150 million, depending on the risk represented by the quantity or quality of oil that is handled by the facility. Any failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to administrative, civil or criminal enforcement actions. We believe we are in compliance with all applicable OPA financial responsibility obligations. Moreover, we are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on us.

Resource Conservation Recovery Act. The Resource Conservation and Recovery Act, also known as “RCRA,” is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. RCRA and many state counterparts specifically exclude from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy” and thus we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate minimal quantities of hazardous wastes. However, these wastes may be regulated by EPA or state agencies as solid waste. In addition, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils, may be regulated as hazardous waste. Although we do not believe the current costs of managing our materials constituting wastes as they are presently classified to be significant, any repeal or modification of the oil and natural gas exploration and production exemption by administrative, legislative or judicial process, or modification of similar exemptions in analogous state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses.

Clean Water Act. The Federal Water Pollution Control Act of 1972, or the Clean Water Act, imposes restrictions and controls on the discharge of produced waters and other pollutants into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water, sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. In furtherance of the Clean Water Act, the EPA promulgated the Spill Prevention, Control, and Countermeasure, or SPCC, regulations, which require certain oil containing facilities to prepare plans and meet construction and operating standards. The SPCC regulations were revised in 2002 and will require the amendment of SPCC plans, if necessary to ensure compliance, in 2004 with the implementation of such amended plans in 2005. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution and that any amendment and subsequent implementation of our SPCC plans will be performed in a timely manner and not have a significant impact on our operations.

Clean Air Act. The Clean Air restricts the emission of air pollutants from many sources, including oil and natural gas operations. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. More stringent regulations governing emissions of toxic air pollutants are being developed by the EPA, and may

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increase the costs of compliance for some facilities. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold or have applied for all permits necessary to our operations.

Consideration of Environmental Issues in Connection with Governmental Approvals. Our operations frequently require licenses, permits and/or other governmental approvals. Several federal statutes, including the Outer Continental Shelf Lands Act, the National Environmental Policy Act, and the Coastal Zone Management Act require federal agencies to evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions. The Outer Continental Shelf Lands Act, for instance, requires the U.S. Department of Interior to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or human environment. Similarly, the National Environmental Policy Act requires the Department of Interior and other federal agencies to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency would have to prepare an environmental assessment and, potentially, an environmental impact statement. The Coastal Zone Management Act, on the other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands associated with various uses, including offshore oil and natural gas development. In obtaining various approvals from the Department of Interior, we must certify that we will conduct our activities in a manner consistent with these regulations.

Employees

As of December 31, 2003, we had 110 full-time employees, including five senior level geoscientists and fourteen petroleum engineers. Our employees are not represented by any labor union. We consider our relations with our employees to be satisfactory, and have never experienced a work stoppage or strike.

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MANAGEMENT

Directors and Executive Officers

The following table sets forth information regarding our executive officers and directors as of March 10, 2004:


Name	Age	Position
James J. Volker	57	Chairman, President and Chief Executive Officer and Director
D. Sherwin Artus	66	Senior Vice President
James R. Casperson	56	Chief Financial Officer
James T. Brown	51	Vice President, Operations
John R. Hazlett	64	Vice President, Acquisitions and Land
Mark R. Williams	47	Vice President, Exploration and Development
Patricia J. Miller	66	Vice President of Human Resources and Corporate Secretary
Michael J. Stevens	38	Controller and Treasurer
Thomas L. Aller	54	Director
Graydon D. Hubbard	70	Director
J. B. Ladd	80	Director
Kenneth R. Whiting	76	Director

Our executive officers are elected by, and serve at the discretion of, our board of directors. The following biographies describe the business experience of our executive officers and directors:

James J. Volker joined us in August 1983 as Vice President of Corporate Development and served in that position through April 1993. In March 1993, he became a contract consultant to us and served in that capacity until August 2000, at which time he became Executive Vice President and Chief Operating Officer. Mr. Volker was appointed President and Chief Executive Officer and a director in January 2002 and Chairman of the Board in January 2004. Mr. Volker was co-founder, Vice President and later President of Energy Management Corporation from 1971 through 1982. He has over thirty years of experience in the oil and natural gas industry. Mr. Volker has a degree in finance from the University of Denver, a MBA from the University of Colorado and has completed H. K. VanPoolen and Associates’ course of study in reservoir engineering.

D. Sherwin Artus joined us in January 1989 as Vice President of Operations and became Executive Vice President and Chief Operating Officer in July 1999. In January 2000, he was appointed President and Chief Executive Officer and a director. In January 2002, he became Senior Vice President. He has been in the oil and natural gas business for forty years. Mr. Artus holds a Bachelor’s Degree in geologic engineering and a Master’s Degree in mining engineering from the South Dakota School of Mines and Technology.

James R. Casperson joined us in February 2000 as Vice President of Finance and Chief Financial Officer. From June 1985 to February 2000, he was founder and president of Casperson, Inc., a private consulting firm. Mr. Casperson has twenty-five years of financial and operational experience in the oil and natural gas industry. Mr. Casperson holds a Bachelor’s Degree from Texas Tech University.

James T. Brown joined us in May 1993 as a consulting engineer. In March 1999, he became Operations Manager and, in January 2000, he became Vice President of Operations. Mr. Brown has twenty-nine years of oil and natural gas experience in the Rocky Mountains, Gulf Coast, California and Alaska. Mr. Brown is a graduate of the University of Wyoming, with a Bachelor’s Degree in civil engineering and a MBA from the University of Denver.

John R. Hazlett joined us in January 1994 as Vice President of Land and Acquisitions. He has forty years of experience in the oil and natural gas industry as a land man and acquisitions team leader. Mr. Hazlett is a graduate of Ft. Hays State College in Hays, Kansas. Mr. Hazlett is a Certified Professional Landman.

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Mark R. Williams joined us in December 1983 as Exploration Geologist, becoming Vice President of Exploration and Development in December 1999. He has twenty-two years of experience in the oil and natural gas industry and his areas of primary technical expertise are in sequence stratigraphy, seismic interpretation and petroleum economics. Mr. Williams is a graduate of the Colorado School of Mines with a Master’s Degree in geology and holds a Bachelor’s Degree in geology from the University of Utah.

Patricia J. Miller joined us in April 1980 as Corporate Secretary and as Secretary to our President, becoming Director of Human Resources in May 1994. In November 2001, she was appointed Vice President of Human Resources. Mrs. Miller attended business school at Otero Junior College in LaJunta, Colorado and at Texas A & I in Kingsville, Texas.

Michael J. Stevens joined us in May 2001 as Controller, and became Treasurer in January 2002. From 1993 until May 2001, he served as Chief Financial Officer, Controller, Secretary and Treasurer at Inland Resources Inc., a company engaged in oil and natural gas exploration and development. He spent seven years in public accounting with Coopers & Lybrand in Minneapolis, Minnesota. He is a graduate of Mankato State University of Minnesota and is a certified public accountant.

Thomas L. Aller has been a director of Whiting Petroleum Corporation since 2003 and has served as a director of Whiting Oil and Gas Corporation since 1997. Mr. Aller has served as Senior Vice President – Energy Delivery of Alliant Energy Corporation and President of Interstate Power and Light Company since January 2004. Prior to that, he served as President of Alliant Energy Investments, Inc. since April 1998 and interim Executive Vice President—Energy Delivery of Alliant Energy Corporation since September 2003. From 1993 to 1998, he served as Vice President of IES Investments. He received his Bachelor’s Degree in political science from Creighton University and his Master’s Degree in municipal administration from the University of Iowa.

Graydon D. Hubbard has served as a director of Whiting Petroleum Corporation since September 2003. He is a retired certified public accountant and was a partner of Arthur Andersen LLP in its Denver office for more than five years prior to his retirement in November 1989. Since 1991, he has served as a director of Allied Motion Technologies Inc., a company engaged in the business of designing, manufacturing and selling motion control products. Mr. Hubbard is also an author. He received his Bachelor’s Degree in accounting from the University of Colorado.

J.B. Ladd has been a director of Whiting Petroleum Corporation since 2003 and has served as a director of Whiting Oil and Gas Corporation since its inception in 1980. He is an independent oil and natural gas operator with offices in Los Angeles, California and Denver, Colorado. He has over 50 years of experience in the oil and natural gas industry working for Texaco and Consolidated Oil and Gas, Inc. and as an independent oil and natural gas operator. He founded Ladd Petroleum Corporation in 1968, which was merged into Utah International in 1973 and later merged into General Electric Company in 1976. Mr. Ladd received a degree in petroleum engineering from the University of Kansas.

Kenneth R. Whiting has been a director of Whiting Petroleum Corporation since 2003 and has served as a director of Whiting Oil and Gas Corporation since its inception in 1980. He was President and Chief Executive Officer of Whiting Oil and Gas Corporation from its inception until 1993, when he was appointed Vice President of International Business for IES Diversified. From 1978 to late 1979 he served as President of Webb Resources, Inc. He has many years of experience in the oil and natural gas industry, including his position as Executive Vice President of Ladd Petroleum Corporation. He was a partner and associate with Holme Roberts & Owen, Attorneys at Law. Mr. Whiting received his Bachelor’s Degree in business from the University of Colorado and his J.D. from the University of Denver.

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Executive Compensation

The following table sets forth certain information concerning the compensation earned each of the last two fiscal years by our Chief Executive Officer and each of our four other most highly compensated executive officers whose total cash compensation exceeded $100,000 in the fiscal year ended December 31, 2003. The persons named in the table are sometimes referred to in this prospectus as the “named executive officers.”

Summary Compensation Table


Name and Principal Position	Year	Annual Compensation		All Other Compensation($)⁽²⁾
Name and Principal Position	Year	Salary($)	Bonus($)⁽¹⁾	All Other Compensation($)⁽²⁾
James J. Volker Chairman, President and Chief Executive Officer	2003 2002	168,713 165,000	262,792 205,041	659,044 —
D. Sherwin Artus Senior Vice President	2003 2002	102,250 100,000	183,211 156,641	680,044 11,000
John R. Hazlett Vice President, Acquisitions and Land	2003 2002	115,952 112,050	139,133 114,941	653,042 11,000
Mark R. Williams Vice President, Exploration and Development	2003 2002	95,406 91,510	150,672 124,819	626,041 11,000
Patricia J. Miller Vice President, Human Resources and Corporate Secretary	2003 2002	99,579 96,228	138,930 114,630	427,988 11,000

⁽¹⁾	Except for incentive bonuses to Mr. Volker of $54,788 for 2002 and $76,000 for 2003, all amounts presented under the Bonus column were paid under Whiting’s Production Participation Plan, which is allocated a specific percentage of net income with respect to certain oil and natural gas wells.

⁽²⁾

These amounts for 2003 consist of (i) matching contributions of $12,000 by Whiting under its 401(k) Employee Savings Plan to each of the named executive officers other than Mr. Volker, who received no matching contribution, and Ms. Miller, who received a matching contribution of $11,960, and (ii) payments valued at $659,044 to Mr. Volker, $668,044 to Mr. Artus, $641,042 to Mr. Hazlett, $614,041 to Mr. Williams and $416,028 to Ms. Miller pursuant to Whiting’s Phantom Equity Plan in connection with Whiting’s initial public offering in November 2003. After withholding for taxes, these payments were made in the form of shares of Whiting common stock resulting in the issuance of 25,052 shares to Mr. Volker, 25,394 shares to Mr. Artus, 24,368 shares to Mr. Hazlett, 23,341 shares to Mr. Williams and 15,814 shares to Ms. Miller. The Phantom Equity Plan terminated after the issuance of such shares.

Director Compensation

Directors who are our employees receive no compensation for service as members of either the Board or Board committees. Directors who are not our employees are paid an annual retainer of $20,000, an annual grant of $30,000 in restricted stock vesting ratably over a three year period and a fee of $1,500 for each Board meeting attended. Members of the Audit Committee will receive an additional cash annual retainer of $2,500 ($12,000 for the chairman) and a fee of $1,500 for each Audit Committee meeting attended. Members of other Board committees will receive an additional cash annual retainer of $1,000 ($5,000 for the chairman) and a fee of $1,000 for each such Board committee meeting attended. In addition, Mr. Whiting receives payments under our Production Participation Plan with respect to his vested plan interests relating to his employment with us from 1982 to 1993. Mr. Whiting was paid $26,679 under the Production Participation Plan for 2003. Mr. Aller receives no compensation for his service on the Board because he is an employee of Alliant Energy Corporation, our former parent company.

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PRINCIPAL HOLDERS OF COMMON STOCK

Management and Directors. The following table sets forth certain information regarding the beneficial ownership of ourcommon stock as of March 10, 2004 by: (i) each of our directors; (ii) each of the executive officers named in the Summary Compensation Table set forth under “Management—Executive Compensation”; and (iii) all of our directors and executive officers (including the named executive officers) as a group. Each of the holders listed below has sole voting and investment power over the shares beneficially owned.


Name of Beneficial Owner	Shares of Common Stock Beneficially Owned	Percent of Common Stock Beneficially Owned
James J. Volker	56,047	*
Thomas L. Aller	1,300	*
Graydon D. Hubbard	3,545	*
J. B. Ladd	13,545	*
Kenneth R. Whiting	1,545	*
D. Sherwin Artus	33,118	*
John R. Hazlett	32,092	*
Mark R. Williams	31,065	*
Patricia J. Miller	21,063	*
All directors, nominees and executive officers as a group (12 persons)	289,766	1.5	%

*	Denotes less than 1%.

Other Beneficial Owners. The following table sets forth certain information regarding beneficial ownership by the only other persons known to us to own more than 5% of our outstanding common stock. The beneficial ownership information set forth below has been reported in filings made by the beneficial owners with the Securities and Exchange Commission.


	Amount and Nature of Beneficial Ownership
	Voting Power		Investment Power		Aggregate	Percent of Class
Name and Address of Beneficial Owner	Sole	Shared	Sole	Shared	Aggregate	Percent of Class
Wellington Management Company, LLP 75 State Street Boston, MA 02109	—	1,479,850	—	1,760,230	1,760,230	9.3	%
Alliant Energy Corporation ⁽¹⁾ 4902 North Biltmore Lane Madison, WI 53718	1,080,000	—	1,080,000	—	1,080,000	5.7	%
T. Rowe Price Associates, Inc. ⁽²⁾ 100 E. Pratt Street Baltimore, MD 21202	184,400	—	979,800	—	979,800	5.2	%

⁽¹⁾	Represents a joint filing by Alliant Energy Corporation and its wholly-owned subsidiary, Alliant Energy Resources, Inc.

⁽²⁾

These securities are owned by various individual and institutional investors for which T. Rowe Price Associates, Inc. serves as investment adviser with power to direct investments and/or sole power to vote the securities. For purposes of the reporting requirements of the Securities Exchange Act of 1934, T. Rowe Price Associates, Inc. is deemed to be the beneficial owner of such securities; however, T. Rowe Price Associates, Inc. has expressly disclaimed beneficial ownership of such securities.

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DESCRIPTION OF OTHER INDEBTEDNESS

The following is information about our indebtedness other than indebtedness outstanding under the indenture. See “Description of the New Notes.”

Whiting Oil and Gas Corporation has a $350.0 million credit agreement with a syndicate of banks. At March 31, 2004, the borrowing base under the credit agreement was $210.0 million with an outstanding principal balance of $145.0 million. The borrowing base under the credit agreement is based on the collateral value of our proved reserves and is subject to redetermination on May 1 and November 1 of each year. The borrowing base of $210 million was reaffirmed on May 1, 2004; however, the borrowing base was reduced to $195.0 million on May 11, 2004 upon our issuance of the old notes. The credit agreement provides for interest only payments until December 20, 2005, when the entire amount borrowed is due. 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 0.25% to 1.0% depending on the utilization percentage of the borrowing base, or (2) at the LIBOR rate plus a margin where the margin varies from 1.5% to 2.25% 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. Based on our borrowing base utilization percentage at March 31, 2004, the LIBOR margin was 1.75%. Commitment fees of 0.375% to 0.5% 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, 2004, all amounts outstanding under the credit agreement accrued interest at an annual rate of 2.95% fixed through August 6, 2004. The credit agreement has covenants that restrict the payment of cash dividends, borrowings, sale of assets, loans to others, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders and requires us to maintain certain debt to EBITDAX (as defined in the credit agreement) ratios and a working capital ratio. In particular, while the credit agreement allows our subsidiaries to make payments to us so that we may pay interest on the old notes and the new notes, it does not allow our subsidiaries to make payments to us to pay principal on the old notes or the new notes. We were in compliance with our covenants under the credit agreement as of March 31, 2004. The credit agreement is secured by a first lien on substantially all of Whiting Oil and Gas Corporation’s assets. Whiting Petroleum Corporation has guaranteed the obligations of Whiting Oil and Gas Corporation under the credit agreement.

If our acquisition of Equity Oil Company closes, then we intend to incorporate into Whiting Oil and Gas Corporation’s existing credit agreement Equity’s outstanding debt under its credit facility, which was $29.0 million as of March 31, 2004. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Subsequent Event.”

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.

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DESCRIPTION OF THE NEW NOTES

You can find the definitions of certain terms used in this description under the subheading “—Certain Definitions.” In this description, the term “Company,” “us” or “we” refers only to Whiting Petroleum Corporation and not to any of its subsidiaries. The term “notes” refers to the old notes and the new notes collectively.

The old notes were, and the new notes will be, issued under and governed by an indenture, dated May 11, 2004, among the Company, the Guarantors and J.P. Morgan Trust Company, National Association, as trustee. The terms of the notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939.

The following description is a summary of the material provisions of the indenture. It does not restate that agreement in its entirety. We urge you to read the indenture because it, and not this description, defines your rights as holders of the notes. Certain defined terms used in this description but not defined below under “—Certain Definitions” have the meanings assigned to them in the indenture.

The registered Holder of a note will be treated as the owner of it for all purposes. Only registered Holders will have rights under the indenture.

Brief Description of the Notes and the Subsidiary Guarantees

The Notes. The notes:

•

are general unsecured obligations of the Company;

•

are subordinated in right of payment to all existing and future Senior Debt (as defined below) of the Company;

•

are pari passu in right of payment with any future senior subordinated Indebtedness of the Company; and

•

are unconditionally guaranteed by the Guarantors on a senior subordinated basis.

The Subsidiary Guarantees. Initially, the notes are guaranteed by the Company’s only operating subsidiary, Whiting Oil and Gas Corporation, which we call “Whiting” in this description, and by one of the Company’s other existing subsidiaries.

Each guarantee of the notes:

•

is a general unsecured obligation of the Guarantor;

•

is subordinated in right of payment to all existing and future Senior Debt of that Guarantor; and

•

is pari passu in right of payment with any future senior subordinated Indebtedness of that Guarantor.

As of March 31, 2004, after giving effect to the issuance of the old notes and the application of the net proceeds thereof as set forth under “Use of Proceeds,” the Company (excluding its subsidiaries) would have had:

•

total Senior Debt of approximately $3.1 million (excluding its guarantee of Whiting Oil and Gas Corporation’s credit agreement), consisting of a note payable;

•

no other senior subordinated Indebtedness; and

•

no Indebtedness contractually subordinated to the notes.

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On the same basis, the Guarantors would have had:

•

total Senior Debt of approximately $1.1 million consisting of borrowings under Whiting’s credit agreement;

•

no other senior subordinated Indebtedness; and

•

no Indebtedness contractually subordinated to their guarantees of the notes.

If the Company’s pending acquisition of Equity Oil Company is completed, then Whiting expects to refinance under its own credit facility the senior debt outstanding under Equity’s credit facility, which was approximately $29.0 million as of December 31, 2003.

As indicated above and as discussed in detail below under the caption “—Subordination,” payments on the notes and under these guarantees will be subordinated to the payment of Senior Debt. The indenture permits us and the Guarantors to incur additional Indebtedness, including additional Senior Debt.

Initially, not all of our existing subsidiaries will guarantee the notes. Furthermore, under the circumstances described below under the subheading “—Certain Covenants—Additional Subsidiary Guarantees,” in the future one or more of our newly created or acquired subsidiaries may not guarantee the notes. In the event of a bankruptcy, liquidation or reorganization of any of these non-guarantor subsidiaries, the non-guarantor subsidiaries will pay the holders of their debt and their trade creditors before they will be able to distribute any of their assets to us. The non-guarantor subsidiaries have no outstanding Indebtedness (other than intercompany Indebtedness). They generated none of our consolidated revenues in the fiscal year ended December 31, 2003 and held less than 1% of our consolidated assets as of December 31, 2003.

As of the date of the indenture, all of our subsidiaries were “Restricted Subsidiaries.” However, under the circumstances described below under the subheading “—Certain Covenants—Designation of Restricted and Unrestricted Subsidiaries,” we are permitted to designate certain of our subsidiaries as “Unrestricted Subsidiaries.” Our Unrestricted Subsidiaries are not subject to many of the restrictive covenants in the indenture. Our Unrestricted Subsidiaries will not guarantee the notes.

Principal, Maturity and Interest

On May 11, 2004, the Company issued the old notes with an aggregate principal amount of $150 million. The Company may issue additional notes from time to time. Any offering of additional notes is subject to the covenant described below under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock.” The notes and any additional notes subsequently issued under the indenture will be treated as a single class for all purposes under the indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase. The Company will issue notes in denominations of $1,000 and integral multiples of $1,000. The notes will mature on May 1, 2012.

Interest on the notes will accrue at the rate of 7 1/4% per annum and will be payable semi-annually in arrears on May 1 and November 1, commencing on November 1, 2004. The Company will make each interest payment to the Holders of record on the immediately preceding April 15 and October 15.

Interest on the notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

Methods of Receiving Payments on the Notes

If a Holder has given wire transfer instructions to the Company, the Company will pay all principal, interest and premium, if any, on that Holder’s notes in accordance with those instructions. All other payments on notes will be made at the office or agency of the paying agent and registrar within the City and State of New York

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unless the Company elects to make interest payments by check mailed to the Holders at their address set forth in the register of Holders.

Paying Agent and Registrar for the Notes

The trustee will initially act as paying agent and registrar. The Company may change the paying agent or registrar without prior notice to the Holders of the notes, and the Company or any of its Domestic Subsidiaries may act as paying agent or registrar.

Transfer and Exchange

A Holder may transfer or exchange notes in accordance with the indenture. The registrar and the trustee may require a Holder to furnish appropriate endorsements and transfer documents in connection with a transfer of notes. No services charge will be imposed by the Company, the trustee or the registrar for any registration of transfer or exchange of notes, but Holders will be required to pay all taxes due on transfer. The Company is not required to transfer or exchange any note selected for redemption. Also, the Company is not required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed.

Subsidiary Guarantees

Initially, Whiting and another of our wholly-owned Subsidiaries, Whiting Programs, Inc., will guarantee the notes. In the future, the notes will be guaranteed by each of the Company’s newly created or acquired Material Domestic Subsidiaries and by any other Restricted Subsidiary of the Company that guarantees its other Indebtedness. See “—Certain Covenants—Additional Subsidiary Guarantees.” These Subsidiary Guarantees will be joint and several obligations of the Guarantors. Each Subsidiary Guarantee will be subordinated to the prior payment in full of all Senior Debt of that Guarantor. The obligations of each Guarantor under its Subsidiary Guarantee will be limited as necessary to prevent that Subsidiary Guarantee from constituting a fraudulent conveyance under applicable law. See “Risk Factors—Risks Relating to the Exchange Offer and the New Notes—Any subsidiary guarantees of the notes may be further subordinated or avoided by a court.”

A Guarantor may not sell or otherwise dispose of all or substantially all of its properties or assets to, or consolidate with or merge with or into (whether or not such Guarantor is the surviving Person), another Person, other than the Company or another Guarantor, unless:

(1) immediately after giving effect to such transaction, no Default or Event of Default exists; and

(2) either:

(a) the Person acquiring the properties or assets in any such sale or other disposition or the Person formed by or surviving any such consolidation or merger (if other than the Guarantor) unconditionally assumes all the obligations of that Guarantor, pursuant to a supplemental indenture substantially in the form specified in the indenture, under the notes, the indenture and its Subsidiary Guarantee on terms set forth therein; or

(b) the Net Proceeds of such sale or other disposition are applied in accordance with the “Asset Sale” provisions of the indenture.

The Subsidiary Guarantee of a Guarantor will be released:

(1) in connection with any sale or other disposition of all or substantially all of the properties or assets of that Guarantor (including by way of merger or consolidation) to a Person that is not (either before or after giving effect to such transaction) a Subsidiary of the Company, if the sale or other disposition complies with the “Asset Sale” provisions of the indenture; or

(2) in connection with any sale or other disposition of all of the Capital Stock of that Guarantor to a Person that is not (either before or after giving effect to such transaction) a Subsidiary of the Company, if the sale or other disposition complies with the “Asset Sale” provisions of the indenture; or

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(3) if the Company designates any Restricted Subsidiary that is a Guarantor as an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture; or

(4) upon Legal Defeasance or Covenant Defeasance as described below under the caption “—Legal Defeasance and Covenant Defeasance” or upon satisfaction and discharge of the indenture as described below under the caption “—Satisfaction and Discharge.”

See “—Repurchase at the Option of Holders—Asset Sales.”

Subordination

The payment of principal of, premium, if any, and interest on the notes will be subordinated in right of payment, as set forth in the indenture, to the prior payment in full in cash of all Obligations in respect of Senior Debt of the Company, whether outstanding on the date of the indenture or thereafter incurred.

Upon any distribution to creditors of the Company:

(1) in a liquidation or dissolution of the Company;

(2) in a bankruptcy, reorganization, insolvency, receivership or similar proceeding relating to the Company or its property;

(3) in an assignment for the benefit of creditors; or

(4) in any marshaling of the Company’s assets and liabilities,

the holders of Senior Debt of the Company will be entitled to receive payment in full in cash of all Obligations due in respect of such Senior Debt (including interest after the commencement of any bankruptcy proceeding at the rate specified in the applicable Senior Debt, whether or not an allowable claim in any such proceeding) before the Holders of notes will be entitled to receive any payment with respect to the notes, and until all Obligations with respect to such Senior Debt are paid in full in cash, any distribution to which the Holders of notes would be entitled shall be made to the holders of such Senior Debt (except, in each case, that Holders of notes may receive and retain Permitted Junior Securities and payments made from a trust described under “—Legal Defeasance and Covenant Defeasance” or “—Satisfaction and Discharge”).

The Company also may not make any payment with respect to the notes (other than Permitted Junior Securities or from a trust described under “—Legal Defeasance and Covenant Defeasance” or “—Satisfaction and Discharge”) if:

(1) a default in the payment of the principal of, premium, if any, or interest on, or any other Obligation in respect of, any Designated Senior Debt occurs and is continuing beyond any applicable grace period; or

(2) any other default occurs and is continuing with respect to any Designated Senior Debt that permits holders of such Designated Senior Debt to accelerate its maturity (or that would permit such holders to accelerate with the giving of notice or the passage of time or both) and the trustee receives a notice of such default (a “Payment Blockage Notice”) from the Company or the holders of such Designated Senior Debt.

Except as provided in the second preceding paragraph, payments on the notes may and will be resumed:

(1) in the case of a payment default, upon the date on which such default is cured or waived; and

(2) in the case of a nonpayment default, upon the earlier of the date on which such nonpayment default is cured or waived or 179 days after the date on which the applicable Payment Blockage Notice is received, unless the maturity of any Designated Senior Debt has been accelerated.

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No new Payment Blockage Notice may be delivered unless and until 360 days have elapsed since the delivery of the immediately prior Payment Blockage Notice.

No nonpayment default that existed or was continuing with respect to any Designated Senior Debt on the date of delivery of any Payment Blockage Notice to the trustee with respect to such Designated Senior Debt will be, or be made, the basis for a subsequent Payment Blockage Notice unless such default has been cured or waived for a period of not less than 90 days.

In the event that the trustee or any Holder receives any payment of any Obligations with respect to the notes (other than Permitted Junior Securities or from the trust described under “—Legal Defeasance and Covenant Defeasance”) at a time when such payment is prohibited by these subordination provisions, such payment shall be held by the trustee or such Holder, in trust for the benefit of, and will be paid over and delivered, as provided in the indenture, to the holders of Senior Debt or their proper representative.

The indenture further requires the Company to promptly notify holders of Designated Senior Debt if payment of the notes is accelerated because of an Event of Default.

The Subsidiary Guarantee of each Guarantor will be subordinated to the Senior Debt of such Guarantor generally to the same extent and in the same manner as the notes are subordinated to the Senior Debt of the Company.

As a result of the subordination provisions described above, in the event of a bankruptcy, liquidation or reorganization or similar proceeding of the Company, Holders of notes may recover less ratably than creditors of the Company who are holders of its Senior Debt. See “Risk Factors—Risks Relating to the Exchange Offer and the New Notes—The new notes and the subsidiary guarantees are subordinated to the senior debt of us and the subsidiary guarantors, respectively, and are effectively subordinated to our and the subsidiary guarantors’ secured debt.”

Optional Redemption

At any time prior to May 1, 2007, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of notes issued under the indenture at a redemption price of 107.25% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date (subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date), with the net cash proceeds of one or more Equity Offerings by the Company, provided that:

(1) at least 65% of the aggregate principal amount of notes issued under the indenture remains outstanding immediately after the occurrence of such redemption (excluding notes held by the Company and its Subsidiaries); and

(2) the redemption occurs within 120 days of the date of the closing of such Equity Offering.

Except pursuant to the preceding paragraph, the notes will not be redeemable at the Company’s option prior to May 1, 2008.

On and after May 1, 2008, the Company may redeem all or a part of the notes upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if any, on the notes redeemed to the applicable redemption date (subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date

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that is on or prior to the redemption date), if redeemed during the twelve-month period beginning on May 1 of the years indicated below:


Year	Percentage
2008	103.6250	%
2009	101.8125	%
2010 and thereafter	100.0000	%

Selection and Notice

If less than all of the notes are to be redeemed at any time, the trustee will select notes for redemption as follows:

(1) if the notes are listed on any national securities exchange, in compliance with the requirements of the principal national securities exchange on which the notes are listed; or

(2) if the notes are not listed on any national securities exchange, on a pro rata basis.

No notes of $1,000 or less can be redeemed in part. Notices of redemption will be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each Holder of notes to be redeemed at its registered address, except that redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the indenture. Notices of redemption may not be conditional.

If any note is to be redeemed in part only, the notice of redemption that relates to that note will state the portion of the principal amount of that note that is to be redeemed. A new note in principal amount equal to the unredeemed portion of the original note will be issued in the name of the Holder of notes upon cancellation of the original note. Notes called for redemption become due on the date fixed for redemption. On and after the redemption date, interest ceases to accrue on notes or portions of them called for redemption.

Mandatory Redemption

Except as set forth below under “—Repurchase at the Option of Holders,” the Company is not required to make mandatory redemption or sinking fund payments with respect to the notes or to repurchase the notes at the option of the Holders.

Repurchase at the Option of Holders

Change of Control

If a Change of Control occurs, each Holder of notes will have the right to require the Company to repurchase all or any part (equal to $1,000 or an integral multiple of $1,000) of that Holder’s notes pursuant to a Change of Control Offer on the terms set forth in the indenture. In the Change of Control Offer, the Company will offer a Change of Control Payment in cash equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest, if any, on the notes repurchased, to the date of settlement (the “Change of Control Settlement Date”), subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the Change of Control Settlement Date. Within 30 days following any Change of Control, the Company will mail a notice to each Holder and the Trustee describing the transaction or transactions that constitute the Change of Control and offering to repurchase notes as of the Change of Control Purchase Date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed, pursuant to the procedures required by the indenture and described in such notice.

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with the repurchase of the notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the indenture by virtue of such conflict.

On the Change of Control Purchase Date, the Company will, to the extent lawful, accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer. Promptly thereafter on the Change of Control Settlement Date the Company will:

(1) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and

(2) deliver or cause to be delivered to the trustee the notes properly accepted together with an officers’ certificate stating the aggregate principal amount of notes or portions of notes being purchased by the Company.

On the Change of Control Settlement Date, the paying agent will mail to each Holder of notes properly tendered the Change of Control Payment for such notes (or, if all the notes are then in global form, make such payment through the facilities of DTC), and the trustee will authenticate and mail (or cause to be transferred by book entry) to each Holder a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any; provided that each new note will be in a principal amount of $1,000 or an integral multiple of $1,000. The Company will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date.

Prior to complying with any of the provisions of this “Change of Control” covenant, but in any event no later than the Change of Control Purchase Date, the Company will either repay all outstanding Senior Debt or obtain the requisite consents, if any, under all agreements governing outstanding Senior Debt to permit the repurchase of notes required by this covenant.

The provisions described above that require the Company to make a Change of Control Offer following a Change of Control will be applicable whether or not any other provisions of the indenture are applicable. Except as described above with respect to a Change of Control, the indenture does not contain provisions that permit the Holders of the notes to require that the Company repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.

The Company will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the time and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by the Company and purchases all notes properly tendered and not withdrawn under the Change of Control Offer.

The definition of Change of Control includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of the Company and its Restricted Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a Holder of notes to require the Company to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of the Company and its Subsidiaries taken as a whole to another Person or group may be uncertain.

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Asset Sales

The Company will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:

(1) the Company (or the Restricted Subsidiary, as the case may be) receives consideration at the time of the Asset Sale at least equal to the fair market value of the assets or Equity Interests issued or sold or otherwise disposed of;

(2) the fair market value is determined by the Company’s Board of Directors and evidenced by a resolution of the Board of Directors set forth in an officers’ certificate delivered to the trustee; and

(3) at least 75% of the consideration received in the Asset Sale by the Company or such Restricted Subsidiary is in the form of cash. For purposes of this provision, each of the following will be deemed to be cash:

(a) any liabilities, as shown on the Company’s or such Restricted Subsidiary’s most recent balance sheet, of the Company or any Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the notes or any Subsidiary Guarantee) that are assumed by the transferee of any such assets pursuant to a customary novation agreement that releases the Company or such Subsidiary from further liability; and

(b) any securities, notes or other obligations received by the Company or any such Restricted Subsidiary from such transferee that are contemporaneously, subject to ordinary settlement periods, converted by the Company or such Subsidiary into cash, to the extent of the cash received in that conversion.

Within 360 days after the receipt of any Net Proceeds from an Asset Sale, the Company or any such Restricted Subsidiary may apply those Net Proceeds at its option to any combination of the following:

(I) to repay Senior Debt and, if the Senior Debt repaid is revolving credit Indebtedness, to correspondingly reduce commitments with respect thereto;

(II) to acquire all or substantially all of the properties or assets of one or more other Persons primarily engaged in the Oil and Gas Business, and, for this purpose, a division or line of business of a Person shall be treated as a separate Person;

(III) to acquire a majority of the Voting Stock of one or more other Persons primarily engaged in the Oil and Gas Business;

(IV) to make one or more capital expenditures; or

(V) to acquire other long-term assets that are used or useful in the Oil and Gas Business.

Pending the final application of any Net Proceeds, the Company or any such Restricted Subsidiary may temporarily reduce revolving credit borrowings or otherwise invest the Net Proceeds in any manner that is not prohibited by the indenture. Any Net Proceeds from Asset Sales that are not applied or invested as provided in the preceding paragraph will constitute “Excess Proceeds.”

On the 361st day after the Asset Sale (or, at the Company’s option, any earlier date), if the aggregate amount of Excess Proceeds then exceeds $20.0 million, the Company will make an Asset Sale Offer to all Holders of notes, and all holders of other Indebtedness that is pari passu with the notes containing provisions similar to those set forth in the indenture with respect to offers to purchase or redeem with the proceeds of sales of assets, to purchase the maximum principal amount of notes and such other pari passu Indebtedness that may be purchased out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of principal amount plus accrued and unpaid interest, if any, to the date of settlement, subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the date of settlement, and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset

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Sale Offer, the Company may use those Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of notes and other pari passu Indebtedness tendered into such Asset Sale Offer exceeds the amount of Excess Proceeds, the trustee will select the notes and such other pari passu Indebtedness to be purchased on a pro rata basis. Upon completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset at zero.

The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the Asset Sale provisions of the indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the indenture by virtue of such conflict.

The Company’s Credit Agreement will prohibit the Company from purchasing any notes, and also provides that certain change of control or asset sale events with respect to the Company would constitute a default or require repayment of the Senior Debt. Any future credit agreements or other agreements relating to Senior Debt to which the Company becomes a party may contain similar restrictions and provisions. In the event a Change of Control or Asset Sale occurs at a time when the Company is prohibited from purchasing notes, the Company could seek the consent of its senior lenders to the purchase of notes or could attempt to refinance the borrowings that contain such prohibition. If the Company does not obtain such a consent or repay such borrowings, the Company will remain prohibited from purchasing notes. In such case, the Company’s failure to purchase tendered notes would constitute an Event of Default under the indenture which would, in turn, constitute a default under such Senior Debt. In such circumstances, the subordination provisions in the indenture would likely restrict payments to the Holders of notes.

Certain Covenants

Restricted Payments

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

(1) declare or pay any dividend or make any other payment or distribution on account of the Company’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) or to the direct or indirect holders of the Company’s or any of its Restricted Subsidiaries’ Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of the Company or payable to the Company or a Restricted Subsidiary of the Company);

(2) purchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving the Company) any Equity Interests of the Company or any direct or indirect parent of the Company;

(3) make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any Indebtedness that is subordinated to the notes or the Subsidiary Guarantees, except a payment of interest or principal at the Stated Maturity thereof; or

(4) make any Restricted Investment (all such payments and other actions set forth in these clauses (1) through (4) above being collectively referred to as “Restricted Payments”),

unless, at the time of and after giving effect to such Restricted Payment:

(1) no Default or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment;

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(2) the Company would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period, have been permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described below under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock;” and

(3) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by the Company and its Restricted Subsidiaries after the date of the indenture (excluding Restricted Payments permitted by clauses (2), (3), (4), (6) and (7) of the next succeeding paragraph), is less than the sum, without duplication, of:

(a) 50% of the Consolidated Net Income of the Company for the period (taken as one accounting period) from April 1, 2004 to the end of the Company’s most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit), plus

(b) 100% of the aggregate net cash proceeds received by the Company (including the fair market value of any Additional Assets to the extent acquired in consideration of Equity Interests of the Company (other than Disqualified Stock)) since the date of the indenture as a contribution to its common equity capital or from the issue or sale of Equity Interests of the Company (other than Disqualified Stock) or from the issue or sale of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities of the Company that have been converted into or exchanged for such Equity Interests (other than Equity Interests (or Disqualified Stock or debt securities) sold to a Subsidiary of the Company), plus

(c) to the extent that any Restricted Investment that was made after the date of the indenture is sold for cash or otherwise liquidated or repaid for cash, the lesser of (i) the cash return of capital with respect to such Restricted Investment (less the cost of disposition, if any) and (ii) the initial amount of such Restricted Investment, plus

(d) to the extent that any Unrestricted Subsidiary of the Company is redesignated as a Restricted Subsidiary after the date of the indenture, the lesser of (i) the fair market value of the Company’s Investment in such Subsidiary as of the date of such redesignation or (ii) such fair market value as of the date on which such Subsidiary was originally designated as an Unrestricted Subsidiary.

So long as no Default or Event of Default has occurred and is continuing or would be caused thereby, the preceding provisions will not prohibit:

(1) the payment of any dividend within 60 days after the date of declaration of the dividend, if at the date of declaration the dividend payment would have complied with the provisions of the indenture;

(2) the redemption, repurchase, retirement, defeasance or other acquisition of any subordinated Indebtedness of the Company or any Guarantor or of any Equity Interests of the Company in exchange for, or out of the net cash proceeds of the substantially concurrent sale (other than to a Subsidiary of the Company) of, Equity Interests of the Company (other than Disqualified Stock); provided that the amount of any such net cash proceeds that are utilized for any such redemption, repurchase, retirement, defeasance or other acquisition will be excluded from clause (3)(b) of the preceding paragraph;

(3) the defeasance, redemption, repurchase, retirement or other acquisition of subordinated Indebtedness of the Company or any Guarantor with the net cash proceeds from an incurrence of, or in exchange for, Permitted Refinancing Indebtedness;

(4) the payment of any dividend by a Restricted Subsidiary of the Company to the holders of its Equity Interests on a pro rata basis;

(5) the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of the Company or any Restricted Subsidiary of the Company held by any current or former director or employee

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of the Company or any of its Restricted Subsidiaries pursuant to any director or employee equity subscription agreement or plan, stock option agreement or similar agreement or plan; provided that the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests may not exceed $1.0 million in any twelve-month period;

(6) the acquisition of Equity Interests by the Company in connection with the exercise of stock options or stock appreciation rights by way of cashless exercise;

(7) the payment of cash in lieu of fractional shares of Capital Stock in connection with any transaction otherwise permitted under this covenant; or

(8) other Restricted Payments in an aggregate amount since the date of the indenture not to exceed $10.0 million.

The amount of all Restricted Payments (other than cash) will be the fair market value on the date of the Restricted Payment of the asset(s) or securities proposed to be transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. The fair market value of any assets or securities that are required to be valued by this covenant will be determined by the Board of Directors, whose determination shall be evidenced by a Board Resolution. The Board of Directors’ determination must be based upon an opinion or appraisal issued by an accounting, appraisal or investment banking firm of national standing if the fair market value exceeds $10.0 million. Not later than the date of making any Restricted Payment (excluding any Restricted Payment described in the preceding clause (2), (3), (4), (6) or (7)) the Company will deliver to the trustee an officers’ certificate stating that such Restricted Payment is permitted and setting forth the basis upon which the calculations required by this “Restricted Payments” covenant were computed, together with a copy of any fairness opinion or appraisal required by the indenture. For purposes of determining compliance with this “Restricted Payments” covenant, in the event that a Restricted Payment meets the criteria of more than one of the categories of Restricted Payments described in the preceding clauses (1) – (8), the Company will be permitted to classify (or later classify or reclassify in whole or in part in its sole discretion) such Restricted Payment in any manner that complies with this covenant.

Incurrence of Indebtedness and Issuance of Preferred Stock

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, “incur”) any Indebtedness (including Acquired Debt), neither the Company nor any Guarantor will issue any Disqualified Stock, and the Company will not permit any of its other Restricted Subsidiaries to issue any shares of preferred stock; provided, however, that the Company and any Guarantor may incur Indebtedness (including Acquired Debt) or issue Disqualified Stock, if the Fixed Charge Coverage Ratio for the Company’s most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock is issued would have been at least 2.0 to 1.0, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or Disqualified Stock had been issued, as the case may be, at the beginning of such four-quarter period.

The first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness (collectively, “Permitted Debt”):

(1) the incurrence by the Company or any of its Restricted Subsidiaries of additional Indebtedness (including letters of credit) under one or more Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) (with letters of credit being deemed to have a principal amount equal to the maximum potential liability of the Company and its Subsidiaries thereunder) not to exceed an amount equal to the greater of (a) $210.0 million and (b) 15% of ACNTA as of the date of such incurrence;

(2) the incurrence by the Company or any of its Restricted Subsidiaries of the Existing Indebtedness;

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(3) the incurrence by the Company and the Guarantors of Indebtedness represented by the notes and the related Subsidiary Guarantees;

(4) the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness represented by Capital Lease Obligations, mortgage financings or purchase money obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of construction or improvement of property, plant or equipment used in the business of the Company or such Restricted Subsidiary, in an aggregate principal amount, including all Permitted Refinancing Indebtedness incurred to refund, refinance or replace any Indebtedness incurred pursuant to this clause (4), not to exceed $10.0 million at any time outstanding;

(5) the incurrence by the Company or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to refund, refinance or replace Indebtedness (other than intercompany Indebtedness) that was permitted by the indenture to be incurred under the first paragraph of this covenant or clause (2) or (3) of this paragraph or this clause (5);

(6) the incurrence by the Company or any of its Restricted Subsidiaries of intercompany Indebtedness between or among the Company and any of its Restricted Subsidiaries; provided, however, that:

(a) if the Company is the obligor on such Indebtedness and a Guarantor is not the obligee, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all Obligations with respect to the notes, or if a Guarantor is the obligor on such Indebtedness and neither the Company nor another Guarantor is the obligee, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all Obligations with respect to the Subsidiary Guarantee of such Guarantor; and

(b) (i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than the Company or a Restricted Subsidiary of the Company and (ii) any sale or other transfer of any such Indebtedness to a Person that is neither the Company nor a Restricted Subsidiary of the Company will be deemed, in each case, to constitute an incurrence of such Indebtedness by the Company or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);

(7) the incurrence by the Company or any of its Restricted Subsidiaries of Hedging Obligations;

(8) the guarantee by the Company or any of the Guarantors of Indebtedness of the Company or any Guarantor that was permitted to be incurred by another provision of this covenant;

(9) the incurrence by the Company or any of its Restricted Subsidiaries of obligations relating to net gas balancing positions arising in the ordinary course of business and consistent with past practice;

(10) the incurrence by the Company’s Unrestricted Subsidiaries of Non-Recourse Debt, provided, however, that if any such Indebtedness ceases to be Non-Recourse Debt of an Unrestricted Subsidiary, such event will be deemed to constitute an incurrence of Indebtedness by a Restricted Subsidiary of the Company that was not permitted by this clause (10);

(11) the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness in respect of bid, performance, surety and similar bonds issued for the account of the Company and any of its Restricted Subsidiaries in the ordinary course of business, including guarantees and obligations of the Company and any of its Restricted Subsidiaries with respect to letters of credit supporting such obligations (in each other than an obligation for money borrowed);

(12) the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness arising from agreements of the Company or any of its Restricted Subsidiaries providing for indemnification, adjustment of purchase price or similar obligations, in each case, incurred or assumed in connection with the disposition of any business, assets or Capital Stock of a Subsidiary, provided that the maximum aggregate liability in

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respect of all such Indebtedness shall at no time exceed the gross proceeds actually received by the Company and its Restricted Subsidiaries in connection with such disposition; and

(13) the incurrence by the Company or any of its Restricted Subsidiaries of additional Indebtedness in an aggregate principal amount (or accreted value, as applicable) at any time outstanding, not to exceed $25.0 million.

For purposes of determining compliance with this “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant, in the event that an item of Indebtedness (including Acquired Debt) meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (13) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, the Company will be permitted to classify (or later classify or reclassify in whole or in part in its sole discretion) such item of Indebtedness in any manner that complies with this covenant. Any indebtedness under Credit Facilities on the date of the indenture shall be considered incurred under the first paragraph of this covenant.

The accrual of interest, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness in the form of additional Indebtedness with the same terms, and the payment of dividends on Disqualified Stock in the form of additional shares of the same class of Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of Disqualified Stock for purposes of this covenant; provided, in each such case, that the amount thereof is included in Fixed Charges of the Company as accrued.

No Senior Subordinated Debt

The Company will not incur, create, issue, assume, guarantee or otherwise become liable for any Indebtedness that is subordinate or junior in right of payment to any Senior Debt of the Company and senior in any respect in right of payment to the notes. No Guarantor will incur, create, issue, assume, guarantee or otherwise become liable for any Indebtedness that is subordinate or junior in right of payment to the Senior Debt of such Guarantor and senior in any respect in right of payment to such Guarantor’s Subsidiary Guarantee.

Liens

The Company will not and will not permit any of its Restricted Subsidiaries to, create, incur, assume or otherwise cause or suffer to exist or become effective any Lien of any kind (other than Permitted Liens) securing Indebtedness or Attributable Debt upon any of their property or assets, now owned or hereafter acquired, unless the notes or any Subsidiary Guarantee of such Restricted Subsidiary, as applicable, is secured on an equal and ratable basis (or on a senior basis to, in the case of obligations subordinated in right of payment to the notes or such Subsidiary Guarantee, as the case may be) with the obligations so secured until such time as such obligations are no longer secured by a Lien.

Dividend and Other Payment Restrictions Affecting Subsidiaries

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:

(1) pay dividends or make any other distributions on its Capital Stock to the Company or any of its Restricted Subsidiaries, or pay any Indebtedness or other obligations owed to the Company or any of its Restricted Subsidiaries;

(2) make loans or advances to the Company or any of its Restricted Subsidiaries; or

(3) transfer any of its properties or assets to the Company or any of its Restricted Subsidiaries.

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However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:

(1) agreements governing Existing Indebtedness and Credit Facilities as in effect on the date of the indenture and any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of those agreements, provided that the amendments, modifications, restatements, renewals, increases, supplements, refundings, replacement or refinancings are not materially more restrictive, taken as a whole, with respect to such dividend and other payment restrictions than those contained in those agreements on the date of the indenture;

(2) the indenture, the notes and the Subsidiary Guarantees;

(3) applicable law;

(4) any instrument governing Indebtedness or Capital Stock of a Person acquired by the Company or any of its Restricted Subsidiaries as in effect at the time of such acquisition, which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired, provided that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the indenture to be incurred;

(5) customary non-assignment provisions in leases entered into in the ordinary course of business and consistent with past practices;

(6) purchase money obligations for property acquired in the ordinary course of business that impose restrictions on that property of the nature described in clause (3) of the preceding paragraph;

(7) any agreement for the sale or other disposition of a Restricted Subsidiary of the Company that restricts distributions by that Restricted Subsidiary pending its sale or other disposition;

(8) Permitted Refinancing Indebtedness, provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced;

(9) Liens securing Indebtedness otherwise permitted to be incurred under the provisions of the covenant described above under the caption “—Liens” that limit the right of the debtor to dispose of the assets subject to such Liens;

(10) provisions with respect to the disposition or distribution of assets or property in joint venture agreements, asset sale agreements, stock sale agreements, agreements respecting Permitted Business Investments and other similar agreements entered into in the ordinary course of business; and

(11) restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business.

Merger, Consolidation or Sale of Assets

The Company may not, directly or indirectly: (1) consolidate or merge with or into another Person (whether or not the Company is the surviving corporation); or (2) sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the properties or assets of the Company and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to another Person, unless:

(1) either: (a) the Company is the surviving corporation; or (b) the Person formed by or surviving any such consolidation or merger (if other than the Company) or to which such sale, assignment, transfer, lease, conveyance or other disposition has been made is a corporation organized or existing under the laws of the United States, any state of the United States or the District of Columbia;

(2) the Person formed by or surviving any such consolidation or merger (if other than the Company) or the Person to which such sale, assignment, transfer, lease, conveyance or other disposition has been made

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assumes all the obligations of the Company under the notes, the indenture and the registration rights agreement pursuant to agreements reasonably satisfactory to the trustee;

(3) immediately after such transaction no Default or Event of Default exists;

(4) the Company or the Person formed by or surviving any such consolidation or merger (if other than the Company), or to which such sale, assignment, transfer, lease, conveyance or other disposition has been made will, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period, be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock;” and

(5) the Company shall have delivered to the trustee an officers’ certificate and an opinion of counsel, each stating that such consolidation, merger or disposition and such supplemental indenture (if any) comply with the indenture.

Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the properties or assets of a Person.

Transactions with Affiliates

The Company will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate (each, an “Affiliate Transaction”), unless:

(1) the Affiliate Transaction is on terms that are no less favorable to the Company or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by the Company or such Restricted Subsidiary with an unrelated Person; and

(2) the Company delivers to the trustee:

(a) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $15.0 million, a resolution of the Board of Directors set forth in an officers’ certificate certifying that such Affiliate Transaction complies with this covenant and that such Affiliate Transaction has been approved by a majority of the disinterested members of the Board of Directors; and

(b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $25.0 million, a written opinion as to the fairness to the Holders of such Affiliate Transaction from a financial point of view issued by an accounting, appraisal or investment banking firm of national standing.

The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:

(1) any employment or severance agreement or other employee compensation agreement, arrangement or plan, or any amendment thereto, entered into by the Company or any of its Restricted Subsidiaries in the ordinary course of business;

(2) transactions between or among any of the Company and its Restricted Subsidiaries;

(3) transactions with a Person that is an Affiliate of the Company solely because the Company owns an Equity Interest in such Person;

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(4) payment of reasonable directors’ fees and other benefits to persons who are not otherwise Affiliates of the Company;

(5) provision of officers’ and directors’ indemnification and insurance in the ordinary course of business to the extent permitted by law;

(6) transactions with any Income Fund Partnership in the ordinary course of business and consistent with past practices;

(7) sales of Equity Interests (other than Disqualified Stock) to Affiliates of the Company; and

(8) Restricted Payments that are permitted by the provisions of the indenture described above under the caption “—Restricted Payments.”

Designation of Restricted and Unrestricted Subsidiaries

The Board of Directors of the Company may designate any Restricted Subsidiary of the Company to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary of the Company is designated as an Unrestricted Subsidiary, the aggregate fair market value of all outstanding Investments owned by the Company and its Restricted Subsidiaries in the Subsidiary properly designated will be deemed to be an Investment made as of the time of the designation and will reduce the amount available for Restricted Payments under the first paragraph of the covenant described above under the caption “—Restricted Payments” or represent Permitted Investments, as determined by the Company. That designation will only be permitted if the Investment would be permitted at that time and if the Subsidiary so designated otherwise meets the definition of an Unrestricted Subsidiary.

The Board of Directors of the Company may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary of the Company; provided that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of the Company of any outstanding Indebtedness of such Unrestricted Subsidiary and such designation will only be permitted if (1) such Indebtedness is permitted under the covenant described above under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock,” calculated on a pro forma basis as if such designation had occurred at the beginning of the four-quarter reference period, and (2) no Default or Event of Default would be in existence following such designation.

Additional Subsidiary Guarantees

If the Company or any of its Restricted Subsidiaries acquires or creates another Material Domestic Subsidiary after the date of the indenture, or if any Restricted Subsidiary that is not already a Guarantor guarantees any other Indebtedness of the Company after such date, then in either case that Subsidiary will become a Guarantor by executing a supplemental indenture and delivering it to the trustee within 20 Business Days of the date on which it was acquired or created or guaranteed Indebtedness of the Company, as the case may be; provided, however, that the foregoing shall not apply to Subsidiaries of the Company that have properly been designated as Unrestricted Subsidiaries in accordance with the indenture for so long as they continue to constitute Unrestricted Subsidiaries.

Sale and Leaseback Transactions

The Company will not, and will not permit any of its Restricted Subsidiaries to, enter into any sale and leaseback transaction; provided that the Company or any Guarantor may enter into a sale and leaseback transaction if:

(1) the Company or that Guarantor, as applicable, could have (a) incurred Indebtedness in an amount equal to the Attributable Debt relating to such sale and leaseback transaction under the Fixed Charge Coverage Ratio test in the first paragraph of the covenant described above under the caption “—Incurrence

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of Indebtedness and Issuance of Preferred Stock” and (b) incurred a Lien to secure such Indebtedness pursuant to the covenant described above under the caption “—Liens;”

(2) the gross cash proceeds of that sale and leaseback transaction are at least equal to the fair market value, as determined in good faith by the Board of Directors and set forth in an officers’ certificate delivered to the trustee, of the property that is the subject of that sale and leaseback transaction; and

(3) the transfer of assets in that sale and leaseback transaction is permitted by, and the Company applies the proceeds of such transaction in compliance with, the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales.”

Business Activities

The Company will not, and will not permit any Restricted Subsidiary to, engage in any business other than the Oil and Gas Business, except to such extent as would not be material to the Company and its Restricted Subsidiaries taken as a whole.

Reports

Whether or not required by the Commission, so long as any notes are outstanding, the Company will file with the Commission for public availability within the time periods specified in the Commission’s rules and regulations (unless the Commission will not accept such a filing), and the Company will furnish to the trustee and, upon its request, to any of the Holders of notes, within five Business Days of filing, or attempting to file, the same with the Commission:

(1) all quarterly and annual financial and other information with respect to the Company and its Subsidiaries that would be required to be contained in a filing with the Commission on Forms 10-Q and 10-K if the Company were required to file such Forms, including a “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and, with respect to the annual information only, a report on the annual financial statements by the Company’s certified independent accountants; and

(2) all current reports that would be required to be filed with the Commission on Form 8-K if the Company were required to file such reports.

If the Company has designated any of its Subsidiaries as Unrestricted Subsidiaries, then the quarterly and annual financial information required by the preceding paragraph will include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in Management’s Discussion and Analysis of Financial Condition and Results of Operations, of the financial condition and results of operations of the Company and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of the Company.

In addition, the Company and the Guarantors have agreed that, for so long as any notes remain outstanding, they will furnish to the Holders and to securities analysts and prospective investors in the notes, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

Events of Default and Remedies

Each of the following is an Event of Default:

(1) default for 30 days in the payment when due of interest on the notes, whether or not prohibited by the subordination provisions of the indenture;

(2) default in payment when due of the principal of, or premium, if any, on the notes, whether or not prohibited by the subordination provisions of the indenture;

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(3) failure by the Company to comply with the provisions described under the captions “—Certain Covenants—Restricted Payments,” “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” or “—Certain Covenants—Merger, Consolidation or Sale of Assets;”

(4) failure by the Company to comply with the provisions described under the captions “—Repurchase at the Option of Holders—Asset Sales” or “—Repurchase at the Option of Holders—Change of Control;”

(5) failure by the Company for 60 days after notice to comply with any of the other agreements in the indenture;

(6) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries), whether such Indebtedness or guarantee now exists, or is created after the date of the indenture, if that default:

(a) is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness (a “Payment Default”); or

(b) results in the acceleration of such Indebtedness prior to its Stated Maturity, and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $15.0 million or more;

(7) failure by the Company or any of its Subsidiaries to pay final judgments aggregating in excess of $15.0 million, which judgments are not paid, discharged or stayed (including a stay pending appeal) for a period of 60 days after the date of such final judgment (or, if later, the date when payment is due pursuant to such judgment);

(8) except as permitted by the indenture, any Subsidiary Guarantee shall be held in any judicial proceeding to be unenforceable or invalid or shall cease for any reason to be in full force and effect or any Guarantor, or any Person acting on behalf of any Guarantor, shall deny or disaffirm its obligations under its Subsidiary Guarantee; and

(9) certain events of bankruptcy, insolvency or reorganization described in the indenture with respect to the Company or any of its Significant Subsidiaries or any group of Subsidiaries of the Company that, taken as a whole, would constitute a Significant Subsidiary.

In the case of an Event of Default arising from certain events of bankruptcy, insolvency or reorganization, with respect to the Company, any Subsidiary of the Company that is a Significant Subsidiary or any group of Subsidiaries of the Company that, taken together, would constitute a Significant Subsidiary, all outstanding notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the trustee or the Holders of at least 25% in principal amount of the then outstanding notes may declare all the notes to be due and payable immediately.

Holders of the notes may not enforce the indenture or the notes except as provided in the indenture. Subject to certain limitations, Holders of a majority in principal amount of the then outstanding notes may direct the trustee in its exercise of any trust or power. The trustee may withhold notice of any continuing Default or Event of Default from Holders of the notes if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal of, or interest or premium, if any, on, the notes.

The Holders of a majority in principal amount of the notes then outstanding by notice to the trustee may on behalf of the Holders of all of the notes waive any existing Default or Event of Default and its consequences under the indenture except a continuing Default or Event of Default in the payment of principal of, or interest or premium, if any, on the notes.

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In the case of any Event of Default occurring by reason of any willful action or inaction taken or not taken by or on behalf of the Company with the intention of avoiding payment of the premium that the Company would have had to pay if the Company then had elected to redeem the notes on or after May 1, 2008 pursuant to the optional redemption provisions of the indenture, an equivalent premium will also become and be immediately due and payable to the extent permitted by law upon the acceleration of the notes. If an Event of Default occurs prior to May 1, 2008 by reason of any willful action (or inaction) taken (or not taken) by or on behalf of the Company with the intention of avoiding the prohibition on redemption of the notes prior to that date, then the premium specified in the indenture with respect to the first year that the notes may be redeemed at the Company’s option (other than with the net cash proceeds of an Equity Offering) will also become immediately due and payable to the extent permitted by law upon the acceleration of the notes.

The Company is required to deliver to the trustee annually a statement regarding compliance with the indenture. Upon becoming aware of any Default or Event of Default, the Company is required to deliver to the trustee a statement specifying such Default or Event of Default.

No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, incorporator or stockholder or other owner of Capital Stock of the Company or any Guarantor, as such, will have any liability for any obligations of the Company or any Guarantor under the notes, the indenture or the Subsidiary Guarantees, or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws.

Legal Defeasance and Covenant Defeasance

The Company may, at its option and at any time, elect to have all of its obligations discharged with respect to the outstanding notes and all obligations of the Guarantors discharged with respect to their Subsidiary Guarantees (“Legal Defeasance”) except for:

(1) the rights of Holders of outstanding notes to receive payments in respect of the principal of, and interest or premium, if any, on such notes when such payments are due from the trust referred to below;

(2) the Company’s obligations with respect to the notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;

(3) the rights, powers, trusts, duties and immunities of the trustee, and the Company’s obligations in connection therewith; and

(4) the Legal Defeasance provisions of the indenture.

In addition, the Company may, at its option and at any time, elect to have its obligations released with respect to certain covenants that are described in the indenture (“Covenant Defeasance”) and thereafter any omission to comply with those covenants will not constitute a Default or Event of Default with respect to the notes. In the event Covenant Defeasance occurs, certain events (not including non-payment, bankruptcy, insolvency or reorganization events) described under “—Events of Default and Remedies” will no longer constitute an Event of Default with respect to the notes. If the Company exercises either its Legal Defeasance or Covenant Defeasance option, each Guarantor will be released and relieved of any obligations under its Subsidiary Guarantee and any security for the notes (other than the trust) will be released.

In order to exercise either Legal Defeasance or Covenant Defeasance:

(1) the Company must irrevocably deposit with the trustee, in trust, for the benefit of the Holders of the notes, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and

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non-callable Government Securities, in amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, to pay the principal of, and interest and premium, if any, on the outstanding notes on the date of fixed maturity or on the applicable redemption date, as the case may be, and the Company must specify whether the notes are being defeased to the date of fixed maturity or to a particular redemption date;

(2) in the case of Legal Defeasance, the Company has delivered to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that:

(a) the Company has received from, or there has been published by, the Internal Revenue Service a ruling; or

(b) since the date of the indenture, there has been a change in the applicable federal income tax law,

in either case to the effect that, and based thereon such opinion of counsel will confirm that, the Holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

(3) in the case of Covenant Defeasance, the Company has delivered to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that the Holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

(4) no Default or Event of Default has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit) or insofar as Events of Default from bankruptcy, insolvency or reorganization events are concerned, at any time in the period ending on the 91st day after the day of deposit;

(5) such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the indenture) to which the Company or any of its Subsidiaries is a party or by which the Company or any of its Subsidiaries is bound;

(6) the Company must have delivered to the trustee an opinion of counsel to the effect that after the 91st day following the deposit (or, if any Holder or Beneficial Owner of notes is an insider of the Company, such later date as counsel may specify in such opinion), the trust funds will not be subject to the effect of any applicable bankruptcy, insolvency, reorganization or similar laws affecting creditors’ rights generally;

(7) the Company must deliver to the trustee an officers’ certificate stating that the deposit was not made by the Company with the intent of preferring the Holders of notes over the other creditors of the Company with the intent of defeating, hindering, delaying or defrauding creditors of the Company or others; and

(8) the Company must deliver to the trustee an officers’ certificate and an opinion of counsel, each stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance have been complied with.

Amendment, Supplement and Waiver

Except as provided in the next three succeeding paragraphs, the indenture or the notes may be amended or supplemented with the consent of the Holders of at least a majority in principal amount of the notes then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes), and any existing default or compliance with any provision of the indenture or the notes may be waived with the consent of the Holders of a majority in principal amount of the then outstanding

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notes (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes).

Without the consent of each Holder affected, an amendment, supplement or waiver may not (with respect to any notes held by a non-consenting Holder):

(1) reduce the principal amount of notes whose Holders must consent to an amendment, supplement or waiver;

(2) reduce the principal of or change the fixed maturity of any note or alter the provisions with respect to the redemption or repurchase of the notes (other than provisions relating to the covenants described above under the caption “—Repurchase at the Option of Holders”);

(3) reduce the rate of or change the time for payment of interest on any note;

(4) waive a Default or Event of Default in the payment of principal of, or interest or premium, if any, on the notes (except a rescission of acceleration of the notes by the Holders of at least a majority in principal amount of the notes and a waiver of the payment default that resulted from such acceleration);

(5) make any note payable in currency other than that stated in the notes;

(6) make any change in the provisions of the indenture relating to waivers of past Defaults or the rights of Holders of notes to receive payments of principal of, or interest or premium, if any, on the notes (other than as permitted in clause (7) below);

(7) waive a redemption or repurchase payment with respect to any note (other than a payment required by one of the covenants described above under the caption “—Repurchase at the Option of Holders”);

(8) release any Guarantor from any of its obligations under its Subsidiary Guarantee or the indenture, except in accordance with the terms of the indenture; or

(9) make any change in the preceding amendment, supplement and waiver provisions.

In addition, any amendment or supplement to, or waiver of, the provisions of the indenture relating to subordination that adversely affects the rights of the Holders of the notes will require the consent of the Holders of at least 75% in principal amount of notes then outstanding.

Notwithstanding the preceding, without the consent of any Holder of notes, the Company, the Guarantors and the trustee may amend or supplement the indenture or the notes:

(1) to cure any ambiguity, defect or inconsistency;

(2) to provide for uncertificated notes in addition to or in place of certificated notes;

(3) to provide for the assumption of the Company’s obligations to Holders of notes in the case of a merger or consolidation or sale of all or substantially all of the Company’s properties or assets;

(4) to make any change that would provide any additional rights or benefits to the Holders of notes or that does not adversely affect the legal rights under the indenture of any Holder, provided that any change to conform the indenture to this offering memorandum will not be deemed to adversely affect the legal rights under the indenture of any holder;

(5) to secure the notes or the Subsidiary Guarantees pursuant to the requirements of the covenant described above under the subheading “—Certain Covenants—Liens;”

(6) to provide for the issuance of additional notes in accordance with the limitations set forth in the indenture;

(7) to add any additional Guarantor or to evidence the release of any Guarantor from its Subsidiary Guarantee, in each case as provided in the indenture;

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(8) to comply with requirements of the Commission in order to effect or maintain the qualification of the indenture under the Trust Indenture Act; or

(9) to evidence or provide for the acceptance of appointment under the indenture of a successor trustee.

Neither the Company nor any of its Subsidiaries shall, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fee or otherwise, to any Beneficial Owner or Holder of any notes for or as an inducement to any consent to any waiver, supplement or amendment of any terms or provisions of the indenture or the notes, unless such consideration is offered to be paid or agreed to be paid to all Beneficial Owners and Holders of the notes which so consent in the time frame set forth in solicitation documents relating to such consent.

Satisfaction and Discharge

The indenture will be discharged and will cease to be of further effect as to all notes issued thereunder (except as to surviving rights of registration of transfer or exchange of the notes and as otherwise specified in the indenture), when:

(1) either:

(a) all notes that have been authenticated, except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has been deposited in trust and thereafter repaid to the Company, have been delivered to the trustee for cancellation; or

(b) all notes that have not been delivered to the trustee for cancellation have become due and payable or will become due and payable within one year by reason of the mailing of a notice of redemption or otherwise and the Company or any Guarantor has irrevocably deposited or caused to be deposited with the trustee as trust funds in trust solely for the benefit of the Holders, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness on the notes not delivered to the trustee for cancellation for principal, premium, if any, and accrued interest to the date of fixed maturity or redemption;

(2) no Default or Event of Default has occurred and is continuing on the date of the deposit or will occur as a result of the deposit and the deposit will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the indenture) to which the Company or any of its Subsidiaries is a party or by which the Company or any of its Subsidiaries is bound;

(3) the Company or any Guarantor has paid or caused to be paid all sums payable by it under the indenture; and

(4) the Company has delivered irrevocable instructions to the trustee under the indenture to apply the deposited money toward the payment of the notes at fixed maturity or the redemption date, as the case may be.

In addition, the Company must deliver an officers’ certificate and an opinion of counsel to the trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

Concerning the Trustee

If the trustee becomes a creditor of the Company or any Guarantor, the indenture limits its right to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest (as defined in the Trust Indenture Act) after a Default has occurred and is continuing, it must eliminate such conflict within 90 days, apply to the Commission for permission to continue or resign.

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The Holders of a majority in principal amount of the then outstanding notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee, subject to certain exceptions. The indenture provides that in case an Event of Default occurs and is continuing, the trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the trustee will be under no obligation to exercise any of its rights or powers under the indenture at the request of any Holder of notes, unless such Holder has offered to the trustee security or indemnity satisfactory to it against any loss, liability or expense.

Governing Law

The indenture, the notes and the Subsidiary Guarantees will be governed by, and construed in accordance with, the laws of the State of New York.

Additional Information

Anyone who receives this offering memorandum may obtain a copy of the indenture and registration rights agreement without charge by writing to Whiting Petroleum Corporation, 1700 Broadway, Suite 2300, Denver, Colorado 80290-2300, Attention: Controller and Treasurer.

Book-Entry, Delivery and Form

Except as set forth below, notes will be represented by one or more permanent, global notes in registered form without interest coupons (the “Global Notes”).

The Global Notes will be deposited upon issuance with the trustee as custodian for The Depository Trust Company (“DTC”), in New York, New York, and registered in the name of DTC’s nominee, Cede & Co., in each case for credit to an account of a direct or indirect participant in DTC as described below. Beneficial interests in the Global Notes may be held through the Euroclear System (“Euroclear”) and Clearstream Banking, S.A. (“Clearstream”) (as indirect participants in DTC).

Except as set forth below, the Global Notes may be transferred, in whole but not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may not be exchanged for Certificated Notes except in the limited circumstances described below. See “—Exchange of Global Notes for Certificated Notes.” Except in the limited circumstances described below, owners of beneficial interests in the Global Notes will not be entitled to receive physical delivery of Certificated Notes.

Transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time.

Depository Procedures

The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. We take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

DTC has advised us that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to

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other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

DTC has also advised us that, pursuant to procedures established by it:

(1) upon deposit of the Global Notes, DTC will credit the accounts of Participants designated by the initial purchasers with portions of the principal amount of the Global Notes; and

(2) ownership of these interests in the Global Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interests in the Global Notes).

Investors in the Global Notes who are Participants in DTC’s system may hold their interests therein directly through DTC. Investors in the Global Notes who are not Participants may hold their interests therein indirectly through organizations (including Euroclear and Clearstream) which are Participants in such system. Euroclear and Clearstream may hold interests in the Global Notes on behalf of their participants through customers’ securities accounts in their respective names on the books of their respective depositories, which are Euroclear Bank S.A./N.V., as operator of Euroclear, and Citibank, N.A., as operator of Clearstream. All interests in a Global Note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of such systems.

The laws of some states require that certain Persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such Persons will be limited to that extent. Because DTC can act only on behalf of Participants, which in turn act on behalf of Indirect Participants, the ability of a Person having beneficial interests in a Global Note to pledge such interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of an interest in the Global Notes will not have notes registered in their names, will not receive physical delivery of Certificated Notes and will not be considered the registered owners or “Holders” thereof under the indenture for any purpose.

Payments in respect of the principal of, and interest and premium, if any, on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered Holder under the indenture. Under the terms of the indenture, the Company and the trustee will treat the Persons in whose names the notes, including the Global Notes, are registered as the owners of the notes for the purpose of receiving payments and for all other purposes. Consequently, neither the Company, the trustee nor any agent of the Company or the trustee has or will have any responsibility or liability for:

(1) any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interests in the Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Notes; or

(2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

DTC has advised us that its current practice, at the due date of any payment in respect of securities such as the notes, is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC

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has reason to believe it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the notes as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the trustee or the Company. Neither the Company nor the trustee will be liable for any delay by DTC or any of its Participants in identifying the beneficial owners of the notes, and the Company and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Transfers between Participants in DTC will be effected in accordance with DTC’s procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

Cross-market transfers between the Participants in DTC, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by its depositary; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

DTC has advised us that it will take any action permitted to be taken by a Holder of notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Notes for definitive notes in registered certificated form (“Certificated Notes”), and to distribute such notes to its Participants.

Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures to facilitate transfers of interests in the Global Notes among participants in DTC, Euroclear and Clearstream, they are under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time. None of the Company, the trustee or any of their respective agents will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for Certificated Notes in minimum denominations of $1,000 and in integral multiples of $1,000, if:

(1) DTC (a) notifies us that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act and in either event the Company fails to appoint a successor depositary within 90 days; or

(2) there has occurred and is continuing an Event of Default and DTC notifies the trustee of its decision to exchange the Global Note for Certificated Notes.

Beneficial interests in a Global Note also may be exchanged for Certificated Notes in the limited other circumstances permitted by the indenture. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures).

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Same Day Settlement and Payment

The Company will make payments in respect of the notes represented by the Global Notes (including principal, premium, if any, and interest) by wire transfer of immediately available funds to the accounts specified by the Global Note Holder. The Company will make all payments of principal, interest and premium, if any, with respect to Certificated Notes by wire transfer of immediately available funds to the accounts specified by the Holders of the Certificated Notes or, if no such account is specified, by mailing a check to each such Holder’s registered address. The notes represented by the Global Notes are expected to be eligible to trade in DTC’s Same-Day Funds Settlement System, and any permitted secondary market trading activity in such notes will, therefore, be required by DTC to be settled in immediately available funds. The Company expects that secondary trading in any Certificated Notes will also be settled in immediately available funds.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a Global Note from a Participant in DTC will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised us that cash received in Euroclear or Clearstream as a result of sales of interests in a Global Note by or through a Euroclear or Clearstream participant to a Participant in DTC will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC’s settlement date.

Certain Definitions

Set forth below are certain defined terms used in the indenture. Reference is made to the indenture for a full disclosure of all such terms, as well as any other capitalized terms used herein for which no definition is provided.

“ACNTA” (Adjusted Consolidated Net Tangible Assets) means (without duplication), as of the date of determination:

(1) the sum of:

(a) discounted future net revenue from proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated in a reserve report prepared as of the end of the Company’s most recently completed fiscal year, which reserve report is prepared or reviewed by independent petroleum engineers as to reserves accounting for at least 80% of all such discounted future net revenue and by the Company’s petroleum engineers with respect to any other such reserves covered by such report, as increased by, as of the date of determination, the discounted future net revenue from:

(i) estimated proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries attributable to acquisitions consummated since the date of such year-end reserve report, and

(ii) estimated crude oil and natural gas reserves of the Company and its Restricted Subsidiaries attributable to extensions, discoveries and other additions and upward determinations of estimates of proved crude oil and natural gas reserves (including previously estimated development costs incurred during the period and the accretion of discount since the prior year end) due to exploration, development or exploitation, production or other activities which reserves were not reflected in such year-end reserve report,

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in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report), and decreased by, as of the date of determination, the discounted future net revenue attributable to

(iii) estimated proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries reflected in such year-end reserve report produced or disposed of since the date of such year-end reserve report and

(iv) reductions in the estimated proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries reflected in such year-end reserve report since the date of such year-end reserve report attributable to downward determinations of estimates of proved crude oil and natural gas reserves due to exploration, development or exploitation, production or other activities conducted or otherwise occurring since the date of such year-end reserve report,

in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report); provided, however, that, in the case of each of the determinations made pursuant to clauses (i) through (iv), such increases and decreases shall be as estimated by the Company’s engineers, except that if as a result of such acquisitions, dispositions, discoveries, extensions or revisions, there is a Material Change, then such increases and decreases in the discounted future net revenue shall be confirmed in writing by an independent petroleum engineer;

(b) the capitalized costs that are attributable to crude oil and natural gas properties of the Company and its Restricted Subsidiaries to which no proved crude oil and natural gas reserves are attributed, based on the Company’s books and records as of a date no earlier than the date of the Company’s latest annual or quarterly financial statements;

(c) the Net Working Capital on a date no earlier than the date of the Company’s latest annual or quarterly financial statements; and

(d) the greater of (I) the net book value on a date no earlier than the date of the Company’s latest annual or quarterly financial statements and (II) the appraised value, as estimated by independent appraisers, of other tangible assets of the Company and its Restricted Subsidiaries as of a date no earlier than the date of the Company’s latest audited financial statements;

(2) minus, to the extent not otherwise taken into account in the immediately preceding clause (1), the sum of:

(a) minority interests;

(b) any net gas balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company’s latest audited financial statements;

(c) the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Company’s year-end reserve report), attributable to reserves subject to participation interests, overriding royalty interests or other interests of third parties, pursuant to participation, partnership, vendor financing or other agreements then in effect, or which otherwise are required to be delivered to third parties;

(d) the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Company’s year-end reserve report), attributable to reserves that are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments on the schedules specified with respect thereto; and

(e) the discounted future net revenue, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments that, based on the estimates of production included in determining the discounted future net revenue specified in the immediately preceding clause (1)(a) (utilizing the same prices utilized in the Company’s year-end reserve report),

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would be necessary to satisfy fully the obligations of the Company and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments on the schedules specified with respect thereto.

If the Company changes its method of accounting for its oil and gas properties from the successful efforts method to the full cost method or a similar method of accounting, ACNTA will continue to be calculated as if the Company were still using the successful efforts method of accounting.

“Acquired Debt” means, with respect to any specified Person:

(1) Indebtedness of any other Person existing at the time such other Person was merged with or into or became a Subsidiary of such specified Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Subsidiary of, such specified Person; and

(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

“Additional Assets” means:

(1) any assets used or useful in the Oil and Gas Business;

(2) the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or another Restricted Subsidiary; or

(3) Capital Stock constituting a minority in any Person that at such time is a Restricted Subsidiary;

provided, however, that any such Restricted Subsidiary described in clause (2) or (3) is primarily engaged in the Oil and Gas Business.

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control,” as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise; provided that beneficial ownership of 10% or more of the Voting Stock of a Person will be deemed to be control. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” have correlative meanings.

“Asset Sale” means:

(1) the sale, lease, conveyance or other disposition of any properties or assets (including by way of a Production Payment or sale and leaseback transaction); provided that the disposition of all or substantially all of the properties or assets of the Company and its Restricted Subsidiaries taken as a whole will be governed by the provisions of the indenture described above under the caption “—Repurchase at the Option of Holders—Change of Control” and/or the provisions described above under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets” and not by the provisions of the Asset Sale covenant; and

(2) the issuance of Equity Interests in any of the Company’s Restricted Subsidiaries or the sale of Equity Interests in any of its Restricted Subsidiaries.

Notwithstanding the preceding, the following items will not be deemed to be Asset Sales:

(1) any single transaction or series of related transactions that involves properties or assets having a fair market value of less than $2.5 million;

(2) a transfer of assets between or among any of the Company and its Restricted Subsidiaries,

(3) an issuance or sale of Equity Interests by a Restricted Subsidiary to the Company or to another Restricted Subsidiary;

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(4) the sale, lease or other disposition of equipment, inventory, accounts receivable or other properties or assets in the ordinary course of business, including, without limitation, any abandonment, farm-in, farm-out, lease or sublease of any oil and gas properties or the forfeiture or other disposition of such properties pursuant to standard form operating agreements, in each case in the ordinary course of business in a manner customary in the Oil and Gas Business;

(5) the sale or other disposition of cash or Cash Equivalents;

(6) a Restricted Payment that is permitted by the covenant described above under the caption “—Certain Covenants—Restricted Payments” or a Permitted Investment;

(7) any trade or exchange by the Company or any Restricted Subsidiary of oil and gas properties or other properties or assets for oil and gas properties or other properties or assets owned or held by another Person, provided that the fair market value of the properties or assets traded or exchanged by the Company or such Restricted Subsidiary (together with any cash) is reasonably equivalent to the fair market value of the properties or assets (together with any cash) to be received by the Company or such Restricted Subsidiary, and provided further that any net cash received must be applied in accordance with the provisions described above under the caption “—Repurchase at the Option of Holders—Asset Sales;”

(8) the creation or perfection of a Lien (but not the sale or other disposition of the properties or assets subject to such Lien);

(9) surrender or waiver of contract rights or the settlement, release or surrender of contract, tort or other claims of any kind; and

(10) the disposition of any of the 390,000 shares of Capital Stock of Delta Petroleum Corporation held by the Company as of the date of the indenture.

“Attributable Debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP.

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only upon the occurrence of a subsequent condition. The terms “Beneficially Owns” and “Beneficially Owned” have correlative meanings.

“Board of Directors” means:

(1) with respect to a corporation, the board of directors of the corporation;

(2) with respect to a partnership, the Board of Directors of the general partner of the partnership; and

(3) with respect to any other Person, the board or committee of such Person serving a similar function.

“Board Resolution” means a copy of a resolution certified by the Secretary or an Assistant Secretary of the applicable Person to have been duly adopted by the Board of Directors of such Person and to be in full force and effect on the date of such certification, and delivered to the trustee.

“Business Day” means each day that is not a Saturday, Sunday or other day on which banking institutions in Denver, Colorado or in New York, New York or another place of payment are authorized or required by law to close.

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“Capital Lease Obligation” means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet in accordance with GAAP.

“Capital Stock” means:

(1) in the case of a corporation, corporate stock;

(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

(3) in the case of a partnership or limited liability company, partnership or membership interests (whether general or limited); and

(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person.

“Cash Equivalents” means:

(1) United States dollars;

(2) securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality of the United States government (provided that the full faith and credit of the United States is pledged in support of those securities) having maturities of not more than six months from the date of acquisition;

(3) certificates of deposit and eurodollar time deposits with maturities of six months or less from the date of acquisition, bankers’ acceptances with maturities not exceeding six months and overnight bank deposits, in each case, with any lender party to the Credit Agreement or with any domestic commercial bank having capital and surplus in excess of $500.0 million and a Thomson Bank Watch Rating of “B” or better;

(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above;

(5) commercial paper having the highest rating obtainable from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and in each case maturing within six months after the date of acquisition; and

(6) money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (5) of this definition.

“Change of Control” means the occurrence of any of the following:

(1) the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets (including Capital Stock of the Restricted Subsidiaries) of the Company and its Restricted Subsidiaries taken as a whole, to any “person” (as that term is used in Section 13(d)(3) of the Exchange Act);

(2) the adoption of a plan relating to the liquidation or dissolution of the Company;

(3) the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any “person” (as that term is used in Section 13(d)(3) of the Exchange Act) becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of the Company, measured by voting power rather than number of shares; or

(4) the first day on which a majority of the members of the Board of Directors of the Company are not Continuing Directors.

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“Commission” or “SEC” means the Securities and Exchange Commission.

“Consolidated Cash Flow” means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period plus:

(1) an amount equal to any extraordinary loss plus any net loss realized by such Person or any of its Restricted Subsidiaries in connection with an Asset Sale, to the extent such losses were deducted in computing such Consolidated Net Income; plus

(2) provision for taxes based on income or profits of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was deducted in computing such Consolidated Net Income; plus

(3) consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued and whether or not capitalized (excluding any interest attributable to Dollar-Denominated Production Payments but including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings), and net of the effect of all payments made or received pursuant to Hedging Obligations, to the extent that any such expense was deducted in computing such Consolidated Net Income; plus

(4) depreciation, depletion and amortization (including amortization of intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period), impairment and other non-cash expenses (excluding any such non-cash expense to the extent that it represents an accrual of or reserve for cash expenses in any future period or amortization of a prepaid cash expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, depletion and amortization, impairment and other non-cash expenses were deducted in computing such Consolidated Net Income; plus

(5) unrealized non-cash losses resulting from foreign currency balance sheet adjustments required by GAAP to the extent such losses were deducted in computing such Consolidated Net Income; minus

(6) non-cash items increasing such Consolidated Net Income for such period, other than items that were accrued in the ordinary course of business; minus (to the extent included in determining Consolidated Net Income):

(7) the sum of (x) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments and (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments, in each case, on a consolidated basis and determined in accordance with GAAP.

“Consolidated Net Income” means, with respect to any specified Person for any period, the aggregate of the Net Income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP; provided that:

(1) the Net Income (but not loss) of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting will be included, but only to the extent of the amount of dividends or distributions paid in cash to the specified Person or a Restricted Subsidiary of the Person;

(2) the Net Income of any Restricted Subsidiary will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that Net Income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders, partners or members;

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(3) the cumulative effect of a change in accounting principles will be excluded;

(4) income resulting from transfers of assets (other than cash) between the Company or any of its Restricted Subsidiaries, on the one hand, and an Unrestricted Subsidiary, on the other hand, will be excluded;

(5) any write-downs of non-current assets will be excluded; provided that any ceiling limitation write-downs under Commission guidelines shall be treated as capitalized costs, as if such write-downs had not occurred; and

(6) any unrealized non-cash gains or losses or charges in respect of hedge or non-hedge derivatives (including those resulting from the application of FAS 133) will be excluded.

In addition, notwithstanding the preceding, for the purposes of the covenant described under “—Certain Covenants—Restricted Payments” only, there shall be excluded from Consolidated Net Income any nonrecurring charges relating to any premium or penalty paid, write off of deferred finance costs or other charges in connection with redeeming or retiring any Indebtedness prior to its Stated Maturity.

“Continuing Directors” means, as of any date of determination, any member of the Board of Directors of the Company who:

(1) was a member of such Board of Directors on the date of the indenture; or

(2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board at the time of such nomination or election.

“Credit Agreement” means that certain Credit Agreement, dated as of December 20, 2002, among Whiting, the financial institutions parties thereto, Bank One, N.A., as Administrative Agent, and Wachovia Bank, National Association, as Syndication Agent, providing for revolving credit borrowings, including any related notes, guarantees, collateral documents, instruments and agreements executed in connection therewith, and in each case as amended, restated, modified, renewed, refunded, replaced or refinanced from time to time.

“Credit Facilities” means one or more debt facilities (including, without limitation, the Credit Agreement), commercial paper facilities or secured capital markets financings, in each case with banks or other institutional lenders or institutional investors providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from (or sell receivables to) such lenders against such receivables), letters of credit or secured capital markets financings, in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced (including refinancing with any capital markets transaction) in whole or in part from time to time.

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“Designated Senior Debt” means:

(1) any Indebtedness outstanding from time to time under the Credit Facilities; and

(2) any other Senior Debt permitted under the indenture the principal amount of which is $25.0 million or more and that is from time to time designated by the Company as “Designated Senior Debt.”

“Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the notes mature. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the

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right to require the Company to repurchase or redeem such Capital Stock upon the occurrence of a change of control or an asset sale will not constitute Disqualified Stock if the terms of such Capital Stock provide that the Company may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption “—Certain Covenants —Restricted Payments.”

“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Domestic Subsidiary” means any Restricted Subsidiary of the Company other than a Foreign Subsidiary.

“Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

“Equity Offering” means any public or private sale of Capital Stock (other than Disqualified Stock) made for cash on a primary basis by the Company after the date of the indenture.

“Exchange Notes” means the notes issued in a Registered Exchange Offer pursuant to the indenture.

“Existing Indebtedness” means the aggregate principal amount of Indebtedness of the Company and its Restricted Subsidiaries (other than Indebtedness under the Credit Agreement which is considered incurred under the first paragraph under the covenant entitled “Incurrence of Indebtedness and Issuance of Preferred Stock”) in existence on the date of the indenture, until such amounts are repaid.

“Fixed Charge Coverage Ratio” means with respect to any specified Person for any four-quarter reference period, the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, guarantees, repays, repurchases or redeems any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems preferred stock subsequent to the commencement of the applicable four-quarter reference period and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such incurrence, assumption, guarantee, repayment, repurchase or redemption of Indebtedness, or such issuance, repurchase or redemption of preferred stock, and the use of the proceeds therefrom as if the same had occurred at the beginning of such period.

In addition, for purposes of calculating the Fixed Charge Coverage Ratio:

(1) acquisitions that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers or consolidations and including any related financing transactions, subsequent to the commencement of the applicable four-quarter reference period and on or prior to the Calculation Date will be given pro forma effect as if they had occurred on the first day of such period, including any Consolidated Cash Flow and any pro forma expense and cost reductions that have occurred or are reasonably expected to occur, in the reasonable judgment of the chief financial or accounting officer of the Company (regardless of whether those cost savings or operating improvements could then be reflected in pro forma financial statements in accordance with Regulation S-X promulgated under the Securities Act or any other regulation or policy of the Commission related thereto);

(2) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses disposed of prior to the Calculation Date, will be excluded; and

(3) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses disposed of prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date.

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“Fixed Charges” means, with respect to any specified Person for any period, the sum, without duplication, of:

(1) the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued (excluding any interest attributable to Dollar-Denominated Production Payments but including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings), and net of the effect of all payments made or received pursuant to Hedging Obligations; plus

(2) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period; plus

(3) any interest expense on Indebtedness of another Person that is guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries, whether or not such guarantee or Lien is called upon; plus

(4) the product of (a) all dividends, whether paid or accrued and whether or not in cash, on any series of preferred stock of such Person or any of its Restricted Subsidiaries, other than dividends on Equity Interests payable solely in Equity Interests of the Company (other than Disqualified Stock) or to the Company or a Restricted Subsidiary of the Company, times (b) a fraction, the numerator of which is one and the denominator of which is one minus the then current combined federal, state and local statutory tax rate of such Person, expressed as a decimal, in each case, on a consolidated basis and in accordance with GAAP.

“Foreign Subsidiary” means any Restricted Subsidiary of the Company that was not formed under the laws of the United States or any state of the United States or the District of Columbia and that conducts substantially all of its operations outside the United States.

“GAAP” means generally accepted accounting principles in the United States, which are in effect on the date of the indenture.

The term “guarantee” means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness. When used as a verb, “guarantee” has a correlative meaning.

“Guarantors” means each of:

(1) Whiting Oil and Gas Corporation and Whiting Programs, Inc., each a Delaware corporation; and

(2) any other Restricted Subsidiary of the Company that becomes a Guarantor in accordance with the provisions of the indenture;

and their respective successors and assigns.

“Hedging Obligations” means, with respect to any specified Person, the obligations of such Person incurred in the normal course of business and consistent with past practices and not for speculative purposes under:

(1) interest rate swap agreements, interest rate cap agreements and interest rate collar agreements entered into with one of more financial institutions and designed to protect the Person or any of its Restricted Subsidiaries entering into the agreement against fluctuations in interest rates with respect to Indebtedness incurred and not for purposes of speculation;

(2) foreign exchange contracts and currency protection agreements entered into with one of more financial institutions and designed to protect the Person or any of its Restricted Subsidiaries entering into the

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agreement against fluctuations in currency exchanges rates with respect to Indebtedness incurred and not for purposes of speculation;

(3) any commodity futures contract, commodity option or other similar agreement or arrangement designed to protect against fluctuations in the price of oil, natural gas or other commodities used, produced, processed or sold by that Person or any of its Restricted Subsidiaries at the time; and

(4) other agreements or arrangements designed to protect such Person or any of its Restricted Subsidiaries against fluctuations in interest rates, commodity prices or currency exchange rates.

“Holder” means a Person in whose name a Note is registered.

“Income Fund Partnerships” means Whiting-Park Production Partnership, Ltd., Whiting-Madison Production Partnership, Ltd. and Whiting 1988 Production Limited Partnership, Ltd., each a Texas limited partnership.

“Indebtedness” means, with respect to any specified Person, any indebtedness of such Person, whether or not contingent:

(1) in respect of borrowed money;

(2) evidenced by bonds, notes, debentures or similar instruments or letters of credit (or reimbursement agreements in respect thereof);

(3) in respect of bankers’ acceptances;

(4) representing Capital Lease Obligations;

(5) representing the balance deferred and unpaid of the purchase price of any property, except any such balance that constitutes an accrued expense or trade payable; or

(6) representing any Hedging Obligations,

if and to the extent any of the preceding items (other than letters of credit and Hedging Obligations) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term “Indebtedness” includes all Indebtedness of others secured by a Lien on any asset of the specified Person (whether or not such Indebtedness is assumed by the specified Person) and, to the extent not otherwise included, the guarantee by the specified Person of any Indebtedness of any other Person (including, with respect to any Production Payment, any warranties or guarantees of production or payment by such Person with respect to such Production Payment, but excluding other contractual obligations of such Person with respect to such Production Payment). Subject to the preceding sentence, neither Dollar-Denominated Production Payments nor Volumetric Production Payments shall be deemed to be Indebtedness.

The amount of any Indebtedness outstanding as of any date will be:

(1) the accreted value of the Indebtedness, in the case of any Indebtedness issued with original issue discount;

(2) in the case of any Hedging Obligation, the termination value of the agreement or arrangement giving rise to such Hedging Obligation that would be payable by such Person at such date; and

(3) the principal amount of the Indebtedness, together with any interest on the Indebtedness that is more than 30 days past due, in the case of any other Indebtedness.

“Investments” means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including guarantees or other obligations), advances or capital contributions (excluding commission, travel and similar advances to officers and employees made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests

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or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If the Company or any Restricted Subsidiary of the Company sells or otherwise disposes of any Equity Interests of any direct or indirect Restricted Subsidiary of the Company such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary of the Company, the Company will be deemed to have made an Investment on the date of any such sale or disposition in an amount equal to the fair market value of the Equity Interests of such Restricted Subsidiary not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption “—Certain Covenants—Restricted Payments.” The acquisition by the Company or any Subsidiary of the Company of a Person that holds an Investment in a third Person will be deemed to be an Investment made by the Company or such Subsidiary in such third Person in an amount equal to the fair market value of the Investment held by the acquired Person in such third Person on the date of any such acquisition in an amount determined as provided in the final paragraph of the covenant described above under the caption “—Certain Covenants—Restricted Payments.”

“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction other than a precautionary financing statement not intended as a security agreement.

“Material Change” means an increase or decrease (excluding changes that result solely from changes in prices and changes resulting from the incurrence of previously estimated future development costs) of more than 25% during a fiscal quarter in the discounted future net revenues from proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries, calculated in accordance with clause (1)(a) of the definition of ACNTA; provided, however, that the following will be excluded from the calculation of Material Change:

(1) any acquisitions during the fiscal quarter of oil and gas reserves that have been estimated by independent petroleum engineers and with respect to which a report or reports of such engineers exist; and

(2) any disposition of properties existing at the beginning of such fiscal quarter that have been disposed of in compliance with the covenant described under “ —Repurchase of the Option of Holders —Assets Sales.”

“Material Domestic Subsidiary” means any one Domestic Subsidiary, or any group of two or more Domestic Subsidiaries, that is not a Guarantor at the time of determination and that at such time has either assets or quarterly revenues in excess of 3.0% of the consolidated assets or quarterly revenues of the Company and its Restricted Subsidiaries, in each case based upon the most recent quarterly financial statements available to the Company.

“Net Income” means, with respect to any specified Person, the net income (loss) of such Person, determined in accordance with GAAP and before any reduction in respect of preferred stock dividends, excluding, however:

(1) any gain (but not loss), together with any related provision for taxes on such gain (but not loss), realized in connection with: (a) any Asset Sale; or (b) the disposition of any securities by such Person or any of its Subsidiaries or the extinguishment of any Indebtedness of such Person or any of its Subsidiaries; and

(2) any extraordinary gain (but not loss), together with any related provision for taxes on such extraordinary gain (but not loss).

“Net Proceeds” means the aggregate cash proceeds received by the Company or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of any non-cash consideration received in any Asset Sale), net of:

(1) the direct costs relating to such Asset Sale, including, without limitation, legal, accounting and investment banking fees, and sales commissions, and any relocation expenses incurred as a result of the Asset Sale,

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(2) taxes paid or payable as a result of the Asset Sale, in each case, after taking into account any available tax credits or deductions and any tax sharing arrangements,

(3) amounts required to be applied to the repayment of Indebtedness, other than under the Credit Facilities, secured by a Lien on the properties or assets that were the subject of such Asset Sale, and

(4) any reserve for adjustment in respect of the sale price of such properties or assets established in accordance with GAAP.

“Net Working Capital” means:

(1) all current assets of the Company and its Restricted Subsidiaries, minus

(2) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness;

in each case, on a consolidated basis and determined in accordance with GAAP.

“Non-Recourse Debt” means Indebtedness:

(1) as to which neither the Company nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness), (b) is directly or indirectly liable as a guarantor or otherwise, or (c) is the lender;

(2) no default with respect to which (including any rights that the holders of the Indebtedness may have to take enforcement action against an Unrestricted Subsidiary) would permit upon notice, lapse of time or both any holder of any other Indebtedness (other than the notes) of the Company or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment of the Indebtedness to be accelerated or payable prior to its Stated Maturity; and

(3) as to which the lenders have been notified in writing that they will not have any recourse to the stock or assets of the Company or any of its Restricted Subsidiaries.

“Obligations” means any principal, premium, if any, interest (including interest accruing on or after the filing of any petition in bankruptcy or for reorganization, whether or not a claim for post-filing interest is allowed in such proceeding), penalties, fees, charges, expenses, indemnifications, reimbursement obligations, damages, guarantees, and other liabilities or amounts payable under the documentation governing any Indebtedness or in respect thereto.

“Oil and Gas Business” means:

(1) the acquisition, exploration, development, operation and disposition of interests in oil, natural gas and other hydrocarbon properties;

(2) the gathering, marketing, treating, processing (but not refining), storage, selling and transporting of any production from those interests; and

(3) any activity necessary, appropriate or incidental to the activities described above.

“Permitted Business Investments” means Investments made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business, including through agreements, transactions, interests or arrangements that permit one to share risk or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including without limitation:

(1) direct or indirect ownership of crude oil, natural gas, other related hydrocarbon and mineral properties or any interest therein or gathering, transportation, processing, storage or related systems; and

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(2) the entry into operating agreements, joint ventures, processing agreements, working interests, royalty interests, mineral leases, farm-in agreements, farm-out agreements, development agreements, production sharing agreements, area of mutual interest agreements, contracts for the sale, transportation or exchange of crude oil and natural gas and related hydrocarbons and minerals, unitization agreements, pooling arrangements, joint bidding agreements, service contracts, partnership agreements (whether general or limited), or other similar or customary agreements, transactions, properties, interests or arrangements and Investments and expenditures in connection therewith or pursuant thereto, in each case made or entered into in the ordinary course of the Oil and Gas Business, excluding, however, Investments in corporations and publicly-traded limited partnerships.

“Permitted Investments” means:

(1) any Investment in the Company or in a Restricted Subsidiary of the Company;

(2) any Investment in Cash Equivalents;

(3) any Investment by the Company or any Restricted Subsidiary of the Company in a Person, if as a result of such Investment:

(a) such Person becomes a Restricted Subsidiary of the Company; or

(b) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its properties or assets to, or is liquidated into, the Company or a Restricted Subsidiary of the Company;

(4) any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales;”

(5) any Investment in any Person solely in exchange for the issuance of Equity Interests (other than Disqualified Stock) of the Company;

(6) any Investments received in compromise of obligations of trade creditors or customers that were incurred in the ordinary course of business, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer;

(7) Hedging Obligations permitted to be incurred under the “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant;

(8) Permitted Business Investments; and

(9) other Investments in any Person having an aggregate fair market value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (9) that are at the time outstanding, not to exceed the greater of $20.0 million and 2.5% of ACNTA.

“Permitted Junior Securities” means:

(1) Equity Interests in the Company or any Guarantor; or

(2) debt securities that are subordinated to all Senior Debt and any debt securities issued in exchange for Senior Debt to substantially the same extent as, or to a greater extent than, the notes and the Subsidiary Guarantees are subordinated to Senior Debt pursuant to the indenture.

“Permitted Liens” means:

(1) Liens securing any Indebtedness under any of the Credit Facilities or any other Senior Debt;

(2) Liens in favor of the Company or the Guarantors;

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(3) Liens on property of a Person existing at the time such Person is merged with or into or consolidated with the Company or any Restricted Subsidiary of the Company, provided that such Liens were in existence prior to the contemplation of such merger or consolidation and do not extend to any assets other than those of the Person merged into or consolidated with the Company or the Restricted Subsidiary;

(4) Liens on property existing at the time of acquisition of the property by the Company or any Restricted Subsidiary of the Company, provided that such Liens were in existence prior to the contemplation of such acquisition;

(5) Liens to secure Indebtedness (including Capital Lease Obligations) permitted by clause (4) of the second paragraph of the covenant entitled “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” covering only the assets acquired with such Indebtedness and proceeds and products thereof;

(6) Liens existing on the date of the indenture; and

(7) Liens incurred in the ordinary course of business of the Company or any Restricted Subsidiary of the Company with respect to obligations that do not exceed $10.0 million at any one time outstanding.

“Permitted Refinancing Indebtedness” means any Indebtedness of the Company or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to extend, refinance, renew, replace, defease or refund other Indebtedness of the Company or any of its Restricted Subsidiaries (other than intercompany Indebtedness); provided that:

(1) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded (plus all accrued interest on the Indebtedness and the amount of all expenses and premiums incurred in connection therewith);

(2) such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded;

(3) if the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded is subordinated in right of payment to the notes or the Subsidiary Guarantees, such Permitted Refinancing Indebtedness is subordinated in right of payment to the notes or the Subsidiary Guarantees on terms at least as favorable to the Holders of notes as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; and

(4) such Indebtedness is not incurred by a Restricted Subsidiary of the Company if the Company is the obligor on the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; provided, however, that a Restricted Subsidiary that is also a Guarantor may guarantee Permitted Refinancing Indebtedness incurred by the Company, whether or not such Restricted Subsidiary was an obligor or guarantor of the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded.

Notwithstanding the preceding, any Indebtedness incurred under Credit Facilities pursuant to the covenant “Incurrence of Indebtedness and Issuance of Preferred Stock” shall be subject only to the refinancing provision in the definition of Credit Facilities and not pursuant to the requirements set forth in the definition of Permitted Refinancing Indebtedness.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

“Production Payments” means, collectively, Dollar-Denominated Production Payments and Volumetric Production Payments.

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“Registered Exchange Offer” has the meaning set forth for such term in the applicable registration rights agreement.

“Restricted Investment” means an Investment other than a Permitted Investment.

“Restricted Subsidiary” of a Person means any Subsidiary of the referent Person that is not an Unrestricted Subsidiary.

“Senior Debt” means

(1) all Indebtedness of the Company or any of its Restricted Subsidiaries outstanding under Credit Facilities and all Hedging Obligations with respect thereto;

(2) any other Indebtedness of the Company or any of its Restricted Subsidiaries permitted to be incurred under the terms of the indenture, unless the instrument under which such Indebtedness is incurred expressly provides that it is on a parity with or subordinated in right of payment to the notes or any Subsidiary Guarantee; and

(3) all Obligations with respect to the items listed in the preceding clauses (1) and (2).

Notwithstanding anything to the contrary in the preceding sentence, Senior Debt will not include:

(a) any intercompany Indebtedness of the Company or any of its Subsidiaries to the Company or any of its Affiliates; or

(b) any Indebtedness that is incurred in violation of the indenture.

For the avoidance of doubt, “Senior Debt” will not include any trade payables or taxes owed or owing by the Company or any Restricted Subsidiary.

“Significant Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the date of the indenture.

“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the original documentation governing such Indebtedness, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.

“Subsidiary” means, with respect to any specified Person:

(1) any corporation, association or other business entity (other than a partnership) of which more than 50% of the total voting power of Voting Stock is at the time owned or controlled, directly or through another Subsidiary, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

(2) any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are that Person or one or more Subsidiaries of that Person (or any combination thereof), but only if such Person and its Subsidiaries are entitled to receive more than 20% of the assets of such partnership upon its dissolution.

“Subsidiary Guarantee” means any guarantee by a Guarantor of the Company’s payment Obligations under the indenture and on the notes.

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“Unrestricted Subsidiary” means any Subsidiary of the Company (other than Whiting) that is designated by the Board of Directors as an Unrestricted Subsidiary pursuant to a Board Resolution, but only to the extent that such Subsidiary:

(1) has no Indebtedness other than Non-Recourse Debt;

(2) is not party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary of the Company unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to the Company or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of the Company;

(3) is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and

(4) has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of the Company or any of its Restricted Subsidiaries.

Any designation of a Subsidiary of the Company as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee the Board Resolution giving effect to such designation and an officers’ certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption “—Certain Covenants—Restricted Payments.” If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary of the Company as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” the Company will be in default of such covenant.

“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all related undertakings and obligations.

“Voting Stock” of any Person as of any date means the Capital Stock of such Person that is at the time entitled (without regard to the occurrence of any contingency) to vote in the election of the Board of Directors of such Person.

“Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing:

(1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by

(2) the then outstanding principal amount of such Indebtedness.

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UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

This summary is of a general nature and is included herein solely for informational purposes. It is not intended to be, nor should it be construed as being, legal or tax advice. No representation with respect to the consequences to any particular purchaser of the new notes is made. Prospective purchasers should consult their own tax advisors with respect to their particular circumstances.

The following is a summary of certain material U.S. federal income tax consequences of the exchange offer to holders of the old notes. The discussion does not consider the aspects of the ownership and disposition of the old notes or the new notes. A discussion of the U.S. federal income tax consequences of holding and disposing of the notes is contained in the offering memorandum with respect to the old notes.

The following summary deals only with notes held as capital assets by purchasers at the issue price who are U.S. holders and not with special classes of holders, such as dealers in securities or currencies, financial institutions, partnerships or other entities treated as partnerships for U.S. federal income tax purposes, life insurance companies, tax-exempt entities, persons holding senior notes as part of a hedge, conversion, constructive sale transaction, straddle or other risk reduction strategy, and persons whose functional currency is not the U.S. dollar. Persons considering the exchanging old notes for new notes should consult their own tax advisors concerning these matters and as to the tax treatment under foreign, state and local tax laws and regulations. We cannot provide any assurance that the Internal Revenue Service will not challenge the conclusions stated below. We have not sought and will not seek a ruling from the IRS on any of the matters discussed below.

This summary is based upon the Internal Revenue Code of 1986, Treasury Regulations, IRS rulings and pronouncements and judicial decisions now in effect, all of which are subject to change at any time. Changes in this area of law may be applied retroactively in a manner that could cause the income tax consequences to vary substantially from the consequences described below, possibly adversely affecting a U.S. holder. The authorities on which this discussion is based are subject to various interpretations, and it is therefore possible that the federal income tax treatment of the purchase, ownership and disposition of the notes may differ from the treatment described below

The exchange of old notes for the new notes under the terms of the exchange offer should not constitute a taxable exchange. As a result:

•

A holder should not recognize taxable gain or loss as a result of exchanging old notes for the new notes under the terms of the exchange offer;

•

The holder’s holding period of the new notes should include the holding period of the old notes exchanged for the new notes; and

•

A holder’s adjusted tax basis in the new notes should be the same as the adjusted tax basis, immediately before the exchange, of the old notes exchanged for the new notes.

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PLAN OF DISTRIBUTION

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the expiration date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale.

We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the new notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes. Any broker-dealer that resells new notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such Exchange Securities may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of new notes and any commission or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The accompanying letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of 180 days after the expiration date, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the accompanying letter of transmittal. We have agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the holders of the notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

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LEGAL MATTERS

The validity of the new notes and guarantees will be passed upon by Foley & Lardner LLP.

INDEPENDENT AUDITORS

The consolidated financial statements of Whiting Petroleum Corporation as of December 31, 2003 and 2002 and for each of the three years in the period ended December 31, 2003 included in this prospectus have been audited by Deloitte & Touche LLP, independent registered public accounting firm, as stated in their report appearing herein (which report expresses an unqualified opinion and includes an explanatory paragraph referring to a change in Whiting Petroleum Corporation’s method of accounting for asset retirement obligations effective January 1, 2003) and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

INDEPENDENT OIL AND GAS CONSULTANTS

The estimated reserve evaluations and related calculations of Cawley Gillespie & Associates, Inc., R. A. Lenser & Associates, Inc. and Ryder Scott Company, L.P., each independent petroleum engineering consultants, included in this prospectus have been included in reliance on the authority of said firms as experts in petroleum engineering.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available to the public over the internet at the SEC’s website at http://www.sec.gov. You may also read and copy any document that we file at the SEC’s public reference room at Judiciary Plaza, 450 Fifth Street, Washington, DC 20549. You may call the SEC at 1-800-SEC-0330 for further information on the public reference room and its copy charges. You may also request a copy of any of these filings, at no cost, by writing to: Corporate Secretary, Whiting Petroleum Corporation, 1700 Broadway, Suite 2300, Denver, Colorado 80290-2300.

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WHITING PETROLEUM CORPORATION

INDEX TO FINANCIAL STATEMENTS


		Page
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2003 and 2002 and as of March 31, 2004 (unaudited)		F-3
Consolidated Statements of Income for the Years ended December 31, 2003, 2002 and 2001 and for the Three Months ended March 31, 2004 and 2003 (unaudited)		F-5
Consolidated Statements of Stockholders’ Equity and Comprehensive Income for the Years ended December 31, 2003, 2002 and 2001 and for the Three Months ended March 31, 2004 (unaudited)		F-6
Consolidated Statements of Cash Flows for the Years ended December 31, 2003, 2002 and 2001 and for the Three Months ended March 31, 2004 and 2003 (unaudited)		F-7
Notes to Consolidated Financial Statements		F-8

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Whiting Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Whiting Petroleum Corporation and Subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the related consolidated statements of income, stockholder’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the financial statements, in 2003 the Company changed its method of accounting for asset retirement obligations to conform to Statement of Financial Accounting Standards No. 143.

/s/ DELOITTE & TOUCHE LLP

February 25, 2004

Denver, Colorado

F-2

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2003 AND 2002 AND AS OF MARCH 31, 2004 (unaudited)

(In thousands, except per share data)


	March 31, 2004			December 31,
	March 31, 2004			2003			2002
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	16,379		$	53,585		$	4,833
Accounts receivable trade		25,785			24,020			22,509
Income taxes and other receivables		—			—			8,162
Prepaid expenses and other		5,003			2,666			3,542

Total current assets		47,167			80,271			39,046
PROPERTY AND EQUIPMENT:
Oil and gas properties, successful efforts method:
Proved properties		626,283			615,764			553,902
Unproved properties		2,031			1,637			1,593
Other property and equipment		2,856			2,684			3,454

Total property and equipment		631,170			620,085			558,949
Less accumulated depreciation, depletion and amortization		(203,143	)		(192,794	)		(154,352	)

Property and equipment—net		428,027			427,291			404,597

OTHER LONG-TERM ASSETS		11,967			9,988			4,825
DEFERRED INCOME TAX ASSET		11,390			18,735

TOTAL	$	498,551		$	536,285		$	448,468

(Continued)

F-3

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2003 AND 2002 AND AS OF MARCH 31, 2004 (unaudited)

(In thousands, except per share data)


	March 31, 2004			December 31,
	March 31, 2004			2003			2002
	(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	11,072		$	15,918		$	8,474
Oil and gas sales payable		2,606			2,406			903
Accrued employee benefits		1,673			5,275			4,259
Production taxes payable		2,550			2,574			2,137
Derivative liability		650			2,145			3,300
Income taxes and other liabilities		227			693			585

Total current liabilities		18,778			29,011			19,658
DEFERRED INCOME TAX LIABILITY		—			—			28,235
ABANDONMENT LIABILITY		23,326			23,021			4,232
PRODUCTION PARTICIPATION PLAN LIABILITY		7,678			7,868			8,053
TAX SHARING LIABILITY		29,390			28,790			—
LONG-TERM DEBT		148,055			188,017			265,472
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY:
Common stock, $.001 par value; 75,000,000 authorized, 18,842,171, 18,750,000 and 18,750,000 issued and outstanding, respectively		19			19			19
Additional paid-in capital		172,307			170,367			53,219
Accumulated other comprehensive income (loss)		1,820			(223	)		(1,550	)
Deferred compensation		(1,875	)		—			—
Retained earnings		99,053			89,415			71,130

Total stockholders’ equity		271,324			259,578			122,818

TOTAL	$	498,551		$	536,285		$	448,468


See notes to consolidated financial statements.		(Concluded)

F-4

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)


	Three-Month Periods Ended March 31,						Years Ended December 31,
	2004			2003			2003			2002			2001
	(unaudited)
REVENUES:
Oil and gas sales	$	47,636		$	49,483		$	175,731		$	122,709		$	125,286
Gain (loss) on oil and gas hedging activities		(1,015	)		(6,658	)		(8,680	)		(3,184	)		2,266
Gain on sale of oil and gas properties		—			—			—			978			11,698
Interest income and other		99			21			330			9			205

Total		46,720			42,846			167,381			120,512			139,455

COSTS AND EXPENSES:
Lease operating		10,549			10,714			43,213			32,867			29,767
Production taxes		3,006			3,020			10,691			7,363			6,482
Depreciation, depletion and amortization		10,729			10,599			41,256			43,601			26,904
Exploration		418			163			3,186			1,811			793
General and administrative		4,001			3,189			12,805			11,980			10,939
Phantom equity plan		—			—			10,914			—			—
Interest expense		2,319			3,226			9,177			10,938			10,233

Total costs and expenses		31,022			30,911			131,242			108,560			85,118

INCOME BEFORE INCOME TAXES AND CUMULATIVE CHANGE IN ACCOUNTING PRINCIPLE		15,698			11,935			36,139			11,952			54,337
INCOME TAX EXPENSE (BENEFIT):
Current		—			650			2,389			(6,408	)		1,815
Deferred		6,060			3,821			11,560			10,631			11,279

Total income tax expense		6,060			4,471			13,949			4,223			13,094

INCOME FROM CONTINUING OPERATIONS		9,638			7,464			22,190			7,729			41,243
CUMULATIVE CHANGE IN ACCOUNTING PRINCIPLE		—			(3,905	)		(3,905	)		—			—

NET INCOME	$	9,638		$	3,559		$	18,285		$	7,729		$	41,243

Earnings per share from continuing operations, basic and diluted	$	0.51		$	0.40		$	1.18		$	0.41		$	2.20
Cumulative change in accounting principle		—			(0.21	)		(0.20	)		—			—

NET INCOME PER COMMON SHARE, BASIC AND DILUTED	$	0.51		$	0.19		$	0.98		$	0.41		$	2.20

WEIGHTED AVERAGE SHARES OUTSTANDING, BASIC AND DILUTED		18,753			18,750			18,750			18,750			18,750

See notes to consolidated financial statements.

F-5

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED MARCH 31, 2004 (unaudited)

(In thousands, except per share data)


	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, 2001	18,750	$	19	$	47,856		$	22,158	$	15		$	—		$	70,048		$	—
Net income	—		—		—			41,243		—			—			41,243			41,243
Unrealized net gain on marketable securities for sale	—		—		—			—		88			—			88			88
Reclass to earnings	—		—		—			—		87			—			87			87

BALANCES—December 31, 2001	18,750		19		47,856			63,401		190			—			111,466		$	41,418

Net income	—		—		—			7,729		—			—			7,729		$	7,729
Unrealized net gain on marketable securities for sale	—		—		—			—		240			—			240			240
Tax contribution from Alliant	—		—		.5,363			—		—			—			5,363			—
Change in derivative instrument fair value	—		—		—			—		(1,980	)		—			(1,980	)		(1,980	)

BALANCES—December 31, 2002	18,750		19		53,219			71,130		(1,550	)		—			122,818		$	5,989

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)	—		—		—			9,638		—			—			9,638		$	9,638
Unrealized net gain on marketable securities for sale (unaudited)	—		—		—			—		1,126			—			1,126			1,126
Change in derivative instrument fair value (unaudited)	—		—		—			—		917			—			917			917
Deferred compensation stock issued (unaudited)	92		—		(1,940	)		—		—			(1,940	)		—			—
Amortization of deferred compensation (unaudited)	—		—		—			—		—			65			65			—

BALANCES—March 31, 2004 (unaudited)	18,842	$	19	$	172,307		$	99,053	$	1,820		$	(1,875	)	$	271,324		$	11,681

See notes to consolidated financial statements.

F-6

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 AND FOR THE THREE MONTHS ENDED MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)


	Three-Month Periods Ended March 31,						Years Ended December 31,
	2004			2003			2003			2002			2001
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	9,638		$	3,559		$	18,285		$	7,729		$	41,243
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of oil and gas properties		—			—			—			(978	)		(11,700	)
Depreciation, depletion and amortization		10,729			10,599			41,256			43,601			35,902
Deferred income taxes		6,060			3,821			11,560			10,631			11,288
Amortization of debt issuance costs		282			300			1,091			71			—
Accretion of tax sharing agreement		600			—			220			—			—
Phantom equity plan		—			—			6,510			—			—
Amortization of deferred compensation		65			—			—			—			—
Cumulative change in accounting principle		—			3,905			3,905			—			—
Changes in assets and liabilities:
Accounts receivable		(1,765	)		(9,603	)		(307	)		(1,129	)		2,165
Income taxes and other receivable		—			1,526			3,814			1,538			(5,670	)
Other assets		(2,342	)		2,143			295			(1,229	)		315
Abandonment liability		(75	)		(64	)		(147	)		(48	)		(8,997	)
Production participation plan		(3,426	)		(2,550	)		651			1,685			1,473
Other current liabilities		(5,464	)		1,977			9,229			710			(3,672	)

Net cash provided by operating activities		14,302			15,613			96,362			62,581			62,347

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(11,508	)		(5,201	)		(47,555	)		(165,443	)		(99,621	)
Acquisition of partnership interests, net of cash received		—			—			(4,453	)		—			—
Proceeds from sale of properties		—			—			—			1,534			19,570
Restricted cash		—			—			—			6,434			(6,434	)

Net cash used in investing activities		(11,508	)		(5,201	)		(52,008	)		(157,475	)		(86,485	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Advances (repayments) from Alliant, net		—			460			4,616			(83,119	)		23,869
Payment on long-term debt		(40,000	)		—			—			—			—
Proceeds from bank loan		—			—			—			185,000			—
Debt issuance costs		—			(83	)		(218	)		(3,171	)		—

Net cash provided (used) by financing activities		(40,000	)		377			4,398			98,710			23,869

NET CHANGE IN CASH AND CASH EQUIVALENTS		(37,206	)		10,789			48,752			3,816			(269	)
CASH AND CASH EQUIVALENTS:
Beginning of period		53,585			4,833			4,833			1,017			1,286

End of period	$	16,379		$	15,622		$	53,585		$	4,833		$	1,017

SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid (refunded) for income taxes	$	499		$	3		$	(1,425	)	$	(7,946	)	$	8,586

Cash paid for interest	$	1,612		$	2,466		$	6,464		$	10,866		$	10,233

NONCASH FINANCING ACTIVITIES:
Alliant debt converted to equity		—			80,931			80,931			—			—

See notes to consolidated financial statements.

F-7

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 public offering of our common stock by Alliant Energy, the Company in effect split its common stock, issuing 18,330 shares for the 1 previously held by Alliant Energy. Alliant Energy historically provided the Company with cash management and other services. 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.

Unaudited Periods—The financial information with respect to the three months ended March 31, 2004 and 2003 is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals necessary for a fair presentation of the results for such period. The results of operations for interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Basis of Presentation of Consolidated Financial Statements—The 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. All significant intercompany balances and transactions have been eliminated in consolidation.

Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make significant estimates. These estimates are an integral part of the financial statements and actual results could differ from those estimates. Certain estimates associated with the carrying amount of oil and gas properties are particularly sensitive to changes in pricing, production rates and cost. A decline in the price of oil or gas or rate of production or increase in costs associated with the operations of oil and gas properties could adversely impact the economic value of the oil and gas properties.

Cash and Cash Equivalents—Cash equivalents consist of money market accounts and investments which have an original maturity of three months or less.

Fair Value of Financial Instruments—The Company’s financial instruments, including cash and cash equivalents, restricted cash, accounts receivable and payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments. The related party debt and bank loan have a recorded value that approximates its fair value as both instruments have variable interest rates tied to current market rates. The Company’s derivative instruments and investment in available for sale securities are marked-to-market with changes in value being recorded in accumulated other comprehensive income.

Concentration of Credit Risk—Substantially all of the Company’s receivables are within the oil and gas industry, primarily from the sale of oil and gas products and billings to working interest owners. Although diversified within many companies, collectibility is dependent upon the general economic conditions of the industry. Most of the receivables are not collateralized and to date, the Company has had minimal bad debts.

Further, our natural gas futures and swap contracts also expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and historically the Company have not experienced material credit losses. The Company

F-8

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

believes that our credit risk related to the natural gas futures and swap contracts is no greater than the risk associated with primary contracts and that the elimination of price risk reduces volatility in our reported results of operations, financial position and cash flows from period to period and lowers our overall business risk; but, as a result of Whiting’s hedging activities the Company may be exposed to greater credit risk in the future. No single purchaser of oil and gas accounted for 10% or more of total sales for the years ended December 31, 2003, 2002 or 2001.

At December 31, 2003 and 2002, the Company had recorded an allowance for doubtful accounts of $300 and $250 and, respectively.

Oil and Gas Producing Activities—The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense. The costs of development wells are capitalized whether productive or nonproductive.

Interest cost is capitalized as a component of property cost for exploration and development projects that require a period of time to be readied for their intended use. During 2003, 2002 and 2001, capitalized interest was insignificant.

Geological and geophysical costs of exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment is recorded for unproved properties if the capitalized costs are not considered to be realizable. Depletion, depreciation and amortization (“DD&A”) of capitalized costs of proved oil and gas properties is provided on a field-by-field basis using the units of production method based upon proved reserves. The computation of DD&A takes into consideration the anticipated proceeds from equipment salvage and the Company’s expected cost to abandon its well interests.

The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares future net undiscounted cash flows on a field-by-field basis using escalated prices to the net recorded book cost at the end of each period. If the net capitalized cost exceeds net future cash flows, then the cost of the property is written down to “fair value,” which is determined using net discounted future cash flows from the producing property. Different pricing assumptions or discount rates could result in a different calculated impairment. During 2003, 2002 and 2001, the Company did not record any impairment charges for proved properties.

Gains and losses are recognized on sales of entire interests in proved and unproved properties. Sales of partial interests are generally treated as recoveries of costs.

Other Property and Equipment—Other property and equipment are stated at cost and depreciated using the straight-line method over a period of four years. Maintenance and repair costs which do not extend the useful lives of the property and equipment are charged to expense as incurred. When other property and equipment is sold or retired, the related costs and accumulated depreciation are removed from the accounts.

As of December 31, 2003 and 2002, the balance of other property and equipment was $2,684 and $3,454, respectively. Depreciation expense was approximately $836, $770, and $710 for the years ended December 31, 2003, 2002 and 2001, respectively.

F-9

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

Bank Fees—Bank fees are being amortized to interest expense using the interest method over the life of the loan.

Reimbursed Overhead—The Company provides various administrative services to its partnerships and owners of certain oil and gas properties for which the Company receives overhead reimbursements. Amounts earned are included as a reduction to general and administrative expense and totaled $5,631, $5,505 and $5,276, for the years ended December 31, 2003, 2002 and 2001, respectively.

Abandonment Liability—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 is accreted at the end of each accounting period through charges to depletion, depreciation and amortization expense. If the obligation is settled for other than the carrying amount, then a gain or loss is recognized on settlement.

Revenue Recognition—The Company uses the sales method to record oil revenues whereby revenue is recognized based on the amount of oil sold to purchasers. The Company uses the entitlements method to record natural gas revenues whereby revenue is recognized for the Company’s share of natural gas produced, regardless of whether the Company has taken its share of the related revenue. In situations where gas imbalances occur, receivables are valued at current market value each reporting period, while liabilities are generally presented based on the price in effect when the imbalance occurred. As of December 31, 2003 and 2002, the Company was in an under produced imbalance position of approximately 206,000 Mcf and 411,000 Mcf.

Derivative 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, transportation availability and price, and general economic conditions. Worldwide political developments have historically also had an impact on oil and gas prices. Periodically, Whiting utilizes oil and gas swaps and forward contracts to mitigate the impact of oil and gas price fluctuations related to its sales of oil and gas. During the years 2003, 2002 and 2001, Whiting entered into a number of oil and gas swaps and forward contracts.

At March 31, 2004, the Company had six commodity swaps or forward contracts outstanding with a fair market value unrealized loss of $650 of which $250 was recorded as a component of accumulated other comprehensive loss and $400 was recorded as an increase to the deferred tax asset.

At December 31, 2003, the Company had five commodity swaps or forward contracts outstanding with a fair market value unrealized loss of $2,145 of which $1,317 was recorded as a component of accumulated other comprehensive loss and $828 was recorded as an increase to the deferred tax asset.

At December 31, 2002, the Company had four commodity swaps or forward contracts outstanding with a fair market value unrealized loss of $3,300 of which $1,980 was recorded as a component of accumulated other comprehensive loss and $1,320 was recorded as a reduction to the deferred tax liability.

F-10

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

During the first quarters of 2004 and 2003, the Company recognized losses of $1,015 and $6,658, respectively, from the settlement of derivative instruments.

For the years ended December 31, 2003, 2002, and 2001, Whiting recognized a loss of approximately $8.7 million, a loss of approximately $3.2 million, and a gain of $2.3 million from the settlement of derivative instruments, respectively.

Marketable Securities—Investments in marketable securities are classified as held-to-maturity, trading securities or available-for-sale. Trading and available-for-sale securities are recorded at estimated market value. Realized gains or losses for both classes of equity investments are determined on a specific identification basis and are included in income. Unrealized gains or losses of available-for-sale securities are excluded from earnings and reported in other comprehensive income.

As of March 31, 2004 and as of December 31, 2003 and 2002, the Company had equity investments in publicly traded securities classified as available-for-sale (included in other long-term assets) with an original cost to the Company of $585 and a fair value of approximately $4,200, $2,367 and $1,300, respectively. As of March 31, 2004, the Company recorded an unrealized holding gain of $3,615; correspondingly $2,220 was recorded as a component of accumulated other comprehensive income and $1,395 was recorded as a decrease to the deferred tax asset. As of December 31, 2003, the Company recorded an unrealized holding gain of $1,782; correspondingly $1,094 was recorded as a component of accumulated other comprehensive income and $688 was recorded as a decrease to the deferred tax asset. As of December 31, 2002, the Company recorded an unrealized holding gain of $715 of which $430 was recorded as a component of accumulated other comprehensive income and $285 was recorded as a deferred tax liability.

Income Taxes—Prior to the Company’s initial public offering in November 2003, the Company was included in the consolidated federal income tax return of Alliant Energy but was treated as a separate entity for income tax purposes. The Company provides deferred federal and state income taxes on all temporary differences between the book and tax basis of the Company’s assets and liabilities.

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 year. 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. There were no potentially dilutive securities of the Company outstanding for any of the periods presented.

Industry Segment and Geographic Information—The Company operates in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of the Company’s operations are conducted in the United States. Consequently, the Company currently reports as a single industry segment.

New Accounting Pronouncements—In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141, Business Combinations which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets, which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The Company did not change or reclassify contractual mineral rights included in oil and gas properties on the balance sheet upon adoption of SFAS No. 142. The Company believes the current accounting of such

F-11

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

mineral rights as part of crude oil and natural gas properties is appropriate under the successful efforts method of accounting. However, there is an alternative view that reclassification of mineral rights to an intangible assets may be necessary. If a reclassification of contractual mineral rights acquired subsequent to July 1, 2001 from oil and gas properties to long term intangible assets is required, then the reclassified amount as of December 31, 2003 and 2002 would be approximately $160.1 million and $161.2 million, respectively. Management does not believe that the ultimate outcome of this issue will have a significant impact on the Company’s cash flows, results of operations or financial condition.

The FASB is currently evaluating the application of certain provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive industries, including oil and gas. The FASB is considering whether the provisions of SFAS No. 141 and SFAS No. 142 require registrants to classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other oil and gas property costs, and provide specific footnote disclosures. In the event the FASB determines that costs associated with mineral rights are required to be classified as intangible assets, the Company currently believes that its financial condition and results of operations would not be affected.

In June 2002 the FASB issued SFAS No. 146, Accounting for Costs Associates with Exit or Disposal Activities. This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (“EITF”) Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. The adoption of this Statement had no impact on the financial statements.

FASB Interpretation No. 45 (FIN 45), Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others was issued in November 2002, by the FASB. FIN 45 requires a guarantor to recognize a liability for the fair value of the obligation it assumes under certain guarantees. Additionally, FIN 45 requires a guarantor to disclose certain aspects of each guarantee, or each group of similar guarantees, including the nature of the guarantee, the maximum exposure under the guarantee, the current carrying amount of any liability for the guarantee, and any recourse provisions allowing the guarantor to recover from third parties any amounts paid under the guarantee. The disclosure provisions of FIN 45 are effective for financial statements for both interim and annual periods ending after December 15, 2002. The fair value measurement provisions of FIN 45 are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The adoption of this Statement did not have a material impact on the financial statements. Under the disclosure provisions, the Company, as part of a 2002 purchase transaction, agreed to share with the seller 50% of the actual price received for certain crude oil production in excess of $19.00 per barrel. The agreement runs through December 31, 2009 and contains a 2% price escalation per year. As a result, the sharing amount at January 1, 2004 increased to 50% of the actual price received in excess of $19.77 per barrel. Approximately 46,000 net barrels of crude oil per month are subject to this sharing agreement. The terms of the agreement do not provide for a maximum amount to be paid. As of December 31, 2003, the Company has paid $3.1 million under this agreement and has accrued an additional $215 as currently payable.

In January 2003, the FASB issued FASB Interpretation No. 46 (as revised in December 2003), Consolidation of Variable Interest Entities (FIN 46). FIN 46 clarifies the application of Accounting Research Bulletin No. 51, Consolidated Financial Statements to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the

F-12

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

entity to finance its activities without additional subordinated support from other parties. FIN 46 requires existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. All companies with interests in variable interest entities created after January 31, 2003, shall apply the provisions of FIN 46 to those entities immediately. The adoption of this Statement had no impact on the Company’s financial statements.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities to amend and clarify financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. The changes in this statement require that contracts with comparable characteristics be accounted for similarly to achieve more consistent reporting of contracts as either derivative or hybrid instruments. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003 and will be applied prospectively. The adoption of this Statement had no impact on our financial statements.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity to classify certain financial instruments as liabilities in statements of financial position. The financial instruments are mandatorily redeemable shares, which the issuing company is obligated to buy back in exchange for cash or other assets, put options and forward purchase contracts, instruments that do or may require the issuer to buy back some of its shares in exchange for cash or other assets, and obligations that can be settled with shares, the monetary value of which is fixed, tied solely or predominantly to a variable such as a market index, or varies inversely with the value of the issuers’ shares. Most of the guidance in SFAS No. 150 is effective for all financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this Statement had no impact on our financial statements.

2.	ASSET RETIREMENT OBLIGATIONS

The Company’s estimated liability for plugging and abandoning its oil and gas wells and certain obligations for previously owned 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 abandonment liability 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 changes in the estimated asset retirement obligation from the amount recorded upon adoption of SFAS No. 143 on January 1, 2003 (including its previously recognized liability in California) through March 31, 2004 and December 31, 2003.


	Three months ended March 31, 2004			Year ended December 31, 2003
	(Unaudited)
Beginning asset retirement obligation	$	23,021		$	4,232
SFAS 143 adoption		—			16,458
Additional liability incurred		—			996
Accretion expense		380			1,482
Liabilities settled		(75	)		(147	)

Ending asset retirement obligation	$	23,326		$	23,021

F-13

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

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

3.	INVESTMENT IN PARTNERSHIPS

The Company sponsors private oil and gas income and development limited partnerships. The partnership agreements generally provide for a capital contribution by the Company of 8% to 10% of total capital for a 13% to 17% interest in the net revenue of the partnerships. Additionally, Whiting is a general partner in various partnerships which own and operate transportation and gas processing facilities. As a general partner in these partnerships, Whiting may be liable to the extent any such partnerships incur liabilities in excess of the value of its assets.

In 2003, the Company purchased the limited partnership interests in three limited partnerships in which the Company was general partner for $4,453.

4.	RELATED PARTY TRANSACTIONS

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 note bears interest at an annual rate of 5%. All principal and interest on the promissory note are due on November 25, 2005 (see Note 5).

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 2003 and 2002, respectively. On March 31, 2003, Alliant Energy converted its outstanding intercompany balance of $80,931 to equity of the Company. The Company incurred approximately $1.2 million, $10.5 million and $10.2 million, in interest expense related to this note during the years ended December 31, 2003, 2002 and 2001, respectively.

The Company holds a 6% working interest in four federal offshore platforms and related onshore plant and equipment in California. Alliant Energy has guaranteed the Company’s obligation in the abandonment of these assets.

The Company provides general and administrative services to its partnerships for which the partnerships are billed monthly. Amounts so charged are based on flat rates provided for in each respective Partnership Agreement. The Company pays operating expenses for its partnerships for which it receives reimbursement. The Company may also advance funds to its partnerships for property development. The amounts due from/to affiliates represent the net amount of advances to partnerships for property development offset by proceeds on sales of property and cash receipts from the sale of oil and gas to be distributed to the partnerships.

5.	LONG-TERM DEBT

Long-term debt consisted of the following at March 31, 2004 and December 31, 2003 and 2002:


	March 31, 2004		December 31, 2003		December 31, 2002
Bank borrowings	$	145,000	$	185,000	$	185,000
Alliant—see Note 4		3,055		3,017		80,472

F-14

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

Credit Facility— The Company has a $350.0 million credit agreement with a syndicate of banks. At December 31, 2003, the credit agreement provided a borrowing base of $210.0 million with an outstanding principal balance of $185.0 million. On February 17, 2004, the Company repaid $40.0 million of the outstanding principal balance from cash on hand in excess of projected drilling and production needs. The borrowing base under the credit agreement is based on the collateral value of the Company’s proved reserves and is subject to redetermination on May 1 and November 1 of each year. If the borrowing base is determined to be lower than the outstanding principal balance then drawn, the Company must immediately pay the difference. The credit agreement provides for interest only payments until December 20, 2005, when the entire amount borrowed is due. Interest accrues, at the Company’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 0.25% to 1.0% depending on the ratio of the amounts borrowed to the borrowing base, or (2) at the LIBOR rate plus a margin where the margin varies from 1.5% to 2.25% depending on the ratio of the amounts borrowed to the borrowing base. At December 31, 2003, all amounts outstanding under the credit agreement bore interest at an annual rate of 3.21% through February 6, 2004.

On February 6, 2004, the Company fixed the rate on the outstanding principal balance at an annual rate of 3.2% through August 6, 2004. The credit agreement has covenants that restrict the payment of cash dividends, borrowings, sale of assets, loans to others, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders and requires the Company to maintain certain debt to EBITDAX (as defined in our credit agreement) ratios and a working capital ratio. The credit agreement also precludes the Company from providing any cash to Alliant Energy except for services rendered on an arm’s-length basis or for income taxes. The Company was in compliance with the covenants under the credit agreement as of December 31, 2003. The credit agreement is secured by a first lien on substantially all of Whiting’s assets.

At March 31, 2004, the borrowing base under the credit facility was $210.0 million with an outstanding principal balance of $145.0 million. The borrowing base of $210 million was reaffirmed on May 1, 2004; however, the borrowing base was reduced to $195.0 million on May 11, 2004 upon completion of our private placement of our 7.25% senior subordinated notes due 2012 (see Note 12). At March 31, 2004, all amounts outstanding under the credit agreement accrued interest at an annual rate of 2.95% fixed through August 6, 2004. The Company was in compliance with the covenants under the credit agreement as of March 31, 2004.

If the Company’s acquisition of Equity Oil Company closes, then the Company expects to incorporate into its credit agreement Equity’s outstanding debt under its credit facility, which was $29.0 million as of December 31, 2003.

On June 3, 2004, the Company entered into an amended and restated credit agreement with the lenders under Whiting Oil and Gas Corporation’s credit agreement to (1) permit the incorporation of Equity Oil Company’s debt under its existing credit facility into Whiting Oil and Gas Corporation’s credit agreement, (2) reaffirm our $195.0 million borrowing base, (3) increase the lenders’ total commitment under the credit agreement to $400.0 million and (4) extend the maturity of the credit agreement to June 2008.

6.	EMPLOYEE BENEFIT PLANS

The Company has a Production Participation Plan for all employees. On an annual basis, management and the Board of Directors allocate interests in oil and gas properties acquired or developed during the year to

F-15

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

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.

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 not be proportionately divided among the remaining participants in a given pool.

Payments to participants of the plan are made annually in cash after year end and amounted to $4.4 million, $3.6 million and $4.1 million for 2003, 2002 and 2001, respectively. The Company has estimated the total discounted obligations, including the amounts above, at December 31, 2003 and 2002 as being $12.3 million and $11.7 million, respectively. Plan expense for 2003, 2002 and 2001 was approximately $4.3 million, $5.3 million and $5.6 million, respectively.

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. As of December 31, 2003, no awards had been made under this plan. During the first quarter of 2004, the Company granted 92,171 shares of restricted stock under this plan. The shares of restricted stock were valued at $1.94 million and are being amortized to general and administrative expense over their three year vesting period.

The Company also had a phantom equity plan as an incentive to employees. The phantom equity plan award was calculated based on the growth of the Company’s proved oil and gas reserves before income taxes from January 1, 2000 to a triggering event, less increases in debt for the same period (the “Value Appreciation”). The Value Appreciation was then multiplied by a sharing percentage of 5%. The completion of the initial public offering in November 2003 constituted a triggering event under the plan and, consequently, the Company’s employees received a $10.9 million award in the form of approximately 420,000 shares of Whiting common stock after withholding of shares for payroll and income taxes. Alliant Energy was required to fund the majority of plan expense by contributing cash and stock to the Company in the combined amount of $10.7 million, which is reflected as an increase to additional paid-in capital. The phantom equity plan is now terminated.

The Company also has a defined contribution retirement plan for all employees. The plan is funded by employee contributions and discretionary Company contributions. The Company’s contributions for 2003, 2002 and 2001 were approximately $665, $529 and $287, respectively. Employer contributions vest ratably at 20% per year over a five year period.

7.	COMMITMENTS AND CONTINGENCIES

The Company leases administrative office space under an operating lease arrangement through October 2005. Net rental expense for 2003, 2002, and 2001 amounted to approximately $1,046, $916 and $823,

F-16

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

respectively. A summary of future minimum lease payments under this noncancellable-operating lease as of December 31, 2003 is as follows (in thousands):


Year Ending December 31
2004	$	1,084
2005		929

Total	$	2,013

The Company had a $2.5 million unused line of credit with a bank. Interest on the line of credit was prime plus one percent. The line of credit was cancelled in February 2003.

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

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 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 effect 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 quarter of 2004 and the fourth quarter of 2003, the Company recognized $600 and $220 of accretion expense, respectively, 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.

8.	INCOME TAXES

Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary

F-17

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

differences between the tax bases of assets and liabilities and amounts reported in the Company’s balance sheet. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liability determines the periodic provision for deferred taxes.

Prior to the Company’s initial public offering, the Company was included in the consolidated federal income tax return of Alliant Energy and calculated its income tax expense on a separate return basis at Alliant Energy’s effective tax rate less any research or Section 29 tax credits generated by the Company. Current tax due under this calculation was paid to Alliant Energy, and current refunds were received from Alliant Energy. All income taxes receivable or payable at December 31, 2003 were to/from Alliant Energy. Section 29 tax credits of $5,363 were generated in 2002 and are expected to be utilized by Alliant Energy in the future. However, on a stand-alone basis Whiting would have been unable to use the credits in its 2002 tax return. Under the Company’s tax separation and indemnification agreement with Alliant Energy, Whiting will be paid for the Section 29 credits when Alliant Energy receives the benefit for them. These credits were reported as a credit to additional paid-in capital in 2002.

Income tax expense differed from amounts computed by applying the U.S. Federal income tax rate as follows (in thousands):


	2003			2002			2001
Expected statutory tax expense at 35%	$	12,649		$	4,183		$	19,018
Research and Section 29 tax credits		—			(178	)		(6,575	)
Excess percentage depletion		(216	)		(82	)		(268	)
State tax expense, net of federal benefit		1,516			300			918

	$	13,949		$	4,223		$	13,093

Temporary differences between the financial statement carrying amounts and tax bases of assets and liabilities that give rise to the net deferred tax asset or (liability) result from the following components (in thousands):


	2003			2002
Oil and gas properties	$	(2,893	)	$	(32,290	)
Production participation plan		2,993			3,020
Available for sale securities		(127	)		(285	)
Derivative instruments		828			1,320
Tax sharing agreement		11,028			—
Abandonment obligations		3,028			—
Net operating loss carryforward		3,878			—

	$	18,735		$	(28,235	)

The Company’s net operating loss will expire in 2023.

F-18

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

9.	OIL AND GAS ACTIVITIES

The Company’s oil and gas activities are conducted entirely in the United States. Costs incurred in oil and gas producing activities are as follows (in thousands):


	2003		2002		2001
Unproved property acquisition	$	242	$	851	$	105
Proved property acquisition		10,914		140,708		66,024
Development		40,336		23,136		32,073
Exploration		3,186		1,811		793

Subtotal		54,678		166,506		98,995
Asset retirement obligations		996		—		—

Total	$	55,674	$	166,506	$	98,995

During 2003, additions to oil and gas properties of approximately $996 were recorded for the estimated costs related to new wells drilled or acquired.

Net capitalized costs related to the Company’s oil and gas producing activities are summarized as follows (in thousands):


	2003			2002
Proven oil and gas properties	$	615,764		$	553,902
Unproven oil and gas properties		1,637			1,593
Accumulated depreciation, depletion and amortization		(191,488	)		(152,595	)

Oil and gas properties—net	$	425,913		$	402,900

During 2003, the Company recorded an addition to oil and gas properties of approximately $10.1 million for the asset retirement costs related to the adoption of SFAS No. 143.

10.

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The estimate of proved reserves and related valuations were based upon the reports of Ryder Scott Company L.P., and Cawley, Gillespie & Associates, Inc. and R. A. Lenser & Associates, Inc., each independent petroleum and geological engineers, and the Company’s engineering staff, in accordance with the provisions of Statement of Financial Accounting Standards No. 69 (“SFAS No. 69”), Disclosures about Oil and Gas Producing Activities. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

F-19

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

The Company’s oil and gas reserves are attributable solely to properties within the United States. A summary of the Company’s changes in quantities of proved oil and gas reserves for the years ended December 31, 2003, 2002 and 2001, are as follows:


	Oil (Mbbls)		Gas (Mmcf)
Balance—January 1, 2001	19,121		157,521
Extensions and discoveries	1,086		9,320
Sales of minerals in place	(677	)	(6,045	)
Purchases of minerals in place	945		89,760
Production	(2,088	)	(19,751	)
Revisions to previous estimates	(3,582	)	(3,284	)

Balance—December 31, 2001	14,805		227,521
Extensions and discoveries	473		2,346
Sales of minerals in place			(953	)


	Oil (Mbbls)		Gas (Mmcf)
Purchases of minerals in place	15,244		58,381
Production	(2,319	)	(21,366	)
Revisions to previous estimates	1,255		(29,941	)

Balance—December 31, 2002	29,458		235,988
Extensions and discoveries	2,327		17,097
Sales of minerals in place	—		—
Purchases of minerals in place	822		3,996
Production	(2,594	)	(21,596	)
Revisions to previous estimates	4,627		(4,474	)

Balance—December 31, 2003	34,640		231,011

Proved developed reserves:
December 31, 2001	11,046		136,817

December 31, 2002	23,784		167,618

December 31, 2003	26,157		171,881

As discussed in “Note 6—Employee Benefit Plans,” all of the Company’s employees participate in the Company’s production participation plan. The reserve disclosures above include oil and gas reserve volumes that have been allocated to the production participation plan. Once allocated to plan participants, the interests are fixed. Allocations prior to 1995 consisted of 2%–3% overriding royalty interest while allocations since 1995 have been 2%–5% of net income from the oil and gas production allocated to the plan.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with the provisions of SFAS No. 69. Future cash inflows were computed by applying prices at year end to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at year end, based on year-end costs and assuming continuation of existing economic conditions.

F-20

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows.

This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Company’s oil and gas properties.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows (in thousands):


	2003			2002			2001
Future cash flows	$	2,297,935		$	1,854,886		$	880,890
Future production costs		(879,390	)		(677,146	)		(379,732	)
Future development costs		(66,326	)		(65,440	)		(75,575	)
Future income tax expense		(336,165	)		(270,516	)		(62,025	)

Future net cash flows		1,016,054			841,784			363,558
10% annual discount for estimated timing of cash flows		(426,490	)		(365,755	)		(151,823	)

Standardized measure of discounted future net cash flows	$	589,564		$	476,029		$	211,735

Future cash flows as shown above were reported without consideration for the effects of hedging transactions outstanding at each period end. If the effects of hedging transactions were included in the computation, then future cash flows would have decreased by $145 in 2003 and $1,300 in 2002 and $0 in 2001, respectively.

The changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows (in thousands):


	2003			2002			2001
	(in thousands)
Beginning of year:	$	476,029		$	211,735		$	519,197
Sale of oil and gas produced, net of production costs		(121,827	)		(80,337	)		(87,273	)
Sales of minerals in place		—			(739	)		(11,200	)
Net changes in prices and production costs		108,115			212,191			(528,096	)
Extensions, discoveries and improved recoveries		47,183			6,587			17,511
Development costs-net		(886	)		(11,328	)		(3,322	)
Purchases of mineral in place		16,745			241,798			84,613
Revisions of previous quantity estimates		43,679			(36,164	)		(16,205	)
Net change in income taxes		(42,082	)		(116,854	)		183,051
Accretion of discount		62,901			24,786			73,516
Changes in production rates and other		(293	)		24,354			(20,057	)

End of year	$	589,564		$	476,029		$	211,735

F-21

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

Average wellhead prices in effect at December 31, 2003, 2002 and 2001 inclusive of adjustments for quality and location used in determining future net revenues related to the standardized measure calculation are as follows (in thousands):


	2003		2002		2001
Oil (per Bbl)	$	29.43	$	28.21	$	17.30
Gas (per Mcf)	$	5.52	$	4.39	$	2.72

11.

QUARTERLY FINANCIAL DATA (UNAUDITED)

The following is a summary of the unaudited financial data for each quarter for the years ended December 31, 2003 and 2002 (in thousands except per share data) (in thousands):


	Three Months Ended
	March 31, 2003			June 30, 2003		September 30, 2003		December 31, 2003
Year ended December 31, 2003:
Oil and gas sales	$	49,483		$	41,883	$	42,272	$	42,093
Income (loss) before income tax and cumulative effect of change in accounting principle		11,935			11,481		12,885		(162	)
Cumulative effect of change in accounting principle		(3,905	)		—		—		—
Net income (loss)		3,559			7,053		7,989		(316	)
Basic net income (loss) per share		0.19			0.38		0.43		(0.02	)


	Three Months Ended
	March 31, 2002			June 30, 2002		September 30, 2002		December 31, 2002
Year ended December 31, 2002:
Oil and gas sales	$	20,190		$	29,552	$	34,657	$	38,310
Income (loss) before income tax		(2,977	)		3,277		6,191		5,461
Net income		(1,822	)		2,050		3,877		3,624
Basic net income (loss) per share		(0.10	)		0.11		0.21		0.19

12.

SUBSEQUENT EVENTS (UNAUDITED)

On February 2, 2004, Whiting announced that the Company entered into a definitive merger agreement to acquire Equity Oil Company. The merger agreement provides for a stock-for-stock merger under which Equity shareholders will receive a fixed exchange ratio of 0.185 shares of Whiting common stock for each share of Equity common stock that they own. In addition, Whiting will assume approximately $29 million of Equity debt. The merger is subject to the approval of shareholders owning two-thirds of the outstanding Equity shares and other customary closing conditions. Equity intends to call a special meeting of its

F-22

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2004 AND 2003 (unaudited)

(In thousands, except per share data)

shareholders during the second quarter of 2004 to consider and vote on the merger. The Company expects to complete the merger as soon as practicable following approval by Equity’s shareholders.

On May 11, 2004, the Company issued, in a private placement, $150,000,000 aggregate principal amount of its 7.25% 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 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, (1) pay dividends on, redeem or repurchase the Company’s capital stock or redeem or repurchase the Company’s subordinated debt; (2) make investments; (3) incur additional indebtedness or issue preferred stock; (4) sell assets; (5) consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries taken as a whole; and (6) 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. Two of the Company’s subsidiaries, Whiting Oil and Gas Corporation 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.

* * * * * *

F-23

GLOSSARY OF OIL AND NATURAL GAS TERMS

We have included below the definitions for certain oil and natural gas terms used in this prospectus:

“3-D seismic” Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

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

“Bcf” One billion cubic feet of natural gas.

“Bcfe” One billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“Boe” Barrels of oil equivalent, determined using the ratio of six thousand cubic feet of natural gas to one barrel of oil.

“completion” The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“horizontal re-entry well” A new well in which a pre-existing wellbore is used as the starting point of a new horizontal borehole. Drilling a horizontal re-entry well typically involves milling a hole in the casing of the pre-existing wellbore and drilling hundreds or thousands of feet from the pre-existing wellbore.

“Mcf” One thousand cubic feet of natural gas.

“Mcf/d” One Mcf per day.

“Mcfe” One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“MMbbls” Millions of barrels of oil or other liquid hydrocarbons.

“MMboe” One million barrels of oil equivalent.

“MMbtu” One million British Thermal Units.

“MMcf” One million cubic feet of natural gas.

“MMcf/d” One MMcf per day.

“MMcfe” One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“MMcfe/d” One MMcfe per day.

“PDNP” Proved developed nonproducing.

“PDP” Proved developed producing.

A-1

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

“PUD” Proved undeveloped.

“pre-tax PV10%” The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated lease operating expense, production taxes and future development costs, using price and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or Federal income taxes and discounted using an annual discount rate of 10%.

“reservoir” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

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

A-2

LOGO

Whiting Petroleum Corporation

Offer to Exchange

All Outstanding

7 1/4% Senior Subordinated Notes due 2012

$150,000,000 Aggregate Principal Amount

for

New 7 1/4% Senior Subordinated Notes due 2012

$150,000,000 Aggregate Principal Amount

PROSPECTUS

June 9, 2004