Edgar Filing: WHITING USA TRUST I

Title of Each Class of

Proposed Maximum

Amount of

Securities to be Registered

Aggregate Offering Price(1)(2)

Registration Fee(3)

Units of Beneficial Interest in Whiting USA Trust I

$195,000,000

sv1

As filed with the Securities and Exchange Commission on November 20, 2007

Registration No. 333-

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933


FORM S-1		FORM S-3
WHITING USA TRUST I		WHITING PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)		(Exact name of registrant as specified in its charter)
Delaware		Delaware
(State or other jurisdiction of incorporation or organization)		(State or other jurisdiction of incorporation or organization)
1311		1311
(Primary Standard Industrial Classification Code No.)		(Primary Standard Industrial Classification Code No.)
26-6053936		20-0098515
(I.R.S. Employer Identification No.)		(I.R.S. Employer Identification No.)
919 Congress Avenue, Suite 500 Austin, Texas 78701 (512) 236-6599		1700 Broadway, Suite 2300 Denver, Colorado 80290-2300 (303) 837-1661
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)		(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
Michael J. Ulrich The Bank of New York Trust Company, N.A., Trustee 919 Congress Avenue, Suite 500 Austin, Texas 78701 (512) 236-6599		James J. Volker Chairman, President and Chief Executive Officer 1700 Broadway, Suite 2300 Denver, Colorado 80290-2300 (303) 837-1661
(Name, address, including zip code, and telephone number, including area code, of agent for service)		(Name, address, including zip code, and telephone number, including area code, of agent for service)

with copies to:


David P. Oelman, Esq. David H. Stone, Esq. Vinson & Elkins L.L.P. 1001 Fannin Street, Suite 2300 Houston, Texas 77002-6760 (713) 758-2222		Benjamin F. Garmer, III, Esq. John K. Wilson, Esq. Foley & Lardner LLP 777 East Wisconsin Avenue Milwaukee, Wisconsin 53202-5306 (414) 271-2400

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If the only securities being registered on this Form are being offered pursuant to dividend or interest reinvestment plans, please check the following box. o

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, other than securities offered only in connection with dividend or interest reinvestment plans, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a registration statement pursuant to General Instruction I.D. or a post-effective amendment thereto that shall become effective upon filing with the Commission pursuant to Rule 462(e) under the Securities Act, check the following box. o

If this Form is a post-effective amendment to a registration statement filed pursuant to General Instruction I.D. filed to register additional securities or additional classes of securities pursuant to Rule 413(b) under the Securities Act, check the following box. o

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

CALCULATION OF REGISTRATION FEE


(1)		Includes trust units to be sold upon exercise of the underwriters’ over-allotment option.

(2)		Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

(3)		Pursuant to Rule 457(p), the $5,986.50 filing fee is offset by $372.12 of the registration fee that was paid on June 28, 2007 pursuant to Rule 456(b), but unused, in connection with Whiting Petroleum Corporation’s Registration Statement No. 333-133889, which was filed on May 8, 2006, and $5,614.38 of the registration fee that was paid, but unused in connection with Whiting Petroleum Corporation’s Registration Statement No. 333-128398, which was filed on September 19, 2005.

The co-registrants hereby amend this registration statement on such date or dates as may be necessary to delay its effective date until the co-registrants shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion dated November 20, 2007

PRELIMINARY PROSPECTUS

Whiting USA Trust I

Trust Units

This is an initial public offering of units of beneficial interest in the Whiting USA Trust I. Whiting Petroleum Corporation, which we refer to as “Whiting” in this prospectus, has formed the trust and, immediately prior to the closing of this offering, Whiting will contribute a term net profits interest in oil and natural gas properties to the trust in exchange for trust units. The net profits interest will entitle the trust to receive 90% of the net proceeds from the sale of production of 9.04 MMBOE (which is equivalent to 8.14 MMBOE attributable to the net profits interest) of proved reserves, after which the trust will terminate. Whiting is offering all of the trust units to be sold in this offering and will receive all proceeds from the offering. Whiting is an independent oil and gas company engaged in acquisition, development, exploitation, production and exploration activities. Whiting’s common stock is traded on the New York Stock Exchange under the symbol “WLL.”

There is no current public market for the trust units. Whiting expects that the public offering price will be between $ and $ . The trust intends to apply to have the trust units approved for listing on the New York Stock Exchange under the symbol “WHX.”

Trust units are units of beneficial interest in the trust and represent undivided interests in the trust. They do not represent any interest in Whiting.

Investing in the trust units involves a high degree of risk. Before buying any trust units, you should read the discussion of material risks of investing in the trust units in “Risk Factors” beginning on page 18 of this prospectus.

These risks include the following:


	•	The amounts of cash distributions by the trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquid prices.

	•	Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the trust units.

	•	Risks associated with the production, gathering, transportation and sale of oil, natural gas and natural gas liquids could adversely affect cash distributions by the trust.

	•	The trust and the trust unitholders will have no voting or managerial rights with respect to the underlying properties. As a result, trust unitholders will have no ability to influence the operation of the underlying properties.

	•	The reserves attributable to the underlying properties are depleting assets and production from those reserves will diminish over time. The trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production.

	•	The amount of cash available for distribution by the trust will be reduced by the amount of any royalties, lease operating expenses, production and property taxes, maintenance expenses, postproduction costs and producing overhead, and payments made with respect to hedge contracts.

	•	There has been no public market for the trust units and no independent appraisal of the value of the net profits interest has been performed.

	•	Conflicts of interest could arise between Whiting and the trust unitholders.

	•	Trust unitholders have limited ability to enforce provisions of the net profits interest.

	•	The trust has not obtained a ruling from the IRS regarding the tax treatment of ownership of the trust units. If the IRS were to determine that the trust is not a “grantor trust” for federal income tax purposes, the trust unitholders may receive different and less advantageous tax treatment than that described in this prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.


	Per Trust Unit	Total
Initial public offering price	$	$
Underwriting discounts and commissions(1)	$	$
Proceeds, before expenses, to Whiting(1)	$	$


(1)		Excludes a structuring fee of $ payable to Raymond James & Associates, Inc. for evaluation, analysis and structuring of the trust.

The underwriters may also exercise their option to purchase from Whiting up to additional trust units to cover over-allotments, if any, at the initial public offering price, less the underwriting discounts and commissions, within 30 days of the date of this prospectus.

The underwriters are offering the trust units as set forth under “Underwriting.” Delivery of the trust units will be made on or about , 2008.

RAYMOND JAMES

The date of this prospectus is , 2008

TABLE OF CONTENTS


	Page

Prospectus Summary		1
Risk Factors		18
Forward-Looking Statements		28
Use of Proceeds		29
The Trust		30
Projected Cash Distributions		31
The Underlying Properties		38
Computation of Net Proceeds		53
Description of the Trust Agreement		56
Description of the Trust Units		61
Trust Units Eligible for Future Sale		63
Federal Income Tax Consequences		65
State Tax Considerations		72
ERISA Considerations		73
Selling Trust Unitholder		74
Underwriting		75
Legal Matters		79
Experts		79
Where You Can Find More Information		80
Glossary of Certain Oil and Natural Gas Terms		81
Index to Financial Statements		F-1
Appendix A — Summary Reserve Report		A-1
Certificate of Trust of Whiting USA Trust I
Trust Agreement
Consent of Deloitte & Touche LLP
Consent of Cawley, Gillespie & Associates, Inc.
Consent of R.A. Lenser & Associates, Inc.
Consent of Ryder Scott Company, L.P.
Consent of Deloitte & Touche LLP
Power of Attorney

You should rely only on the information contained in this prospectus. The trust has not, Whiting has not and the underwriters have not, authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. The trust has not, Whiting has not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only.

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. To understand this offering fully, you should read the entire prospectus carefully, including the risk factors and the financial statements and notes to those statements. You will find definitions for terms relating to the oil and natural gas business in “Glossary of Certain Oil and Natural Gas Terms.” Cawley, Gillespie & Associates, Inc., an independent engineering firm, provided the estimates of proved oil and natural gas reserves for the underlying properties described in this prospectus, in a reserve report as of September 30, 2007, which is referred to in this prospectus as the “reserve report.” A summary of the reserve report is located at the back of this prospectus as Appendix A. References to “Whiting” in this prospectus include Whiting Petroleum Corporation and its wholly-owned subsidiaries, Whiting Oil and Gas Corporation and Equity Oil Company. Unless otherwise indicated, all information in this prospectus assumes no exercise of the underwriters’ option to purchase additional trust units.

Whiting USA Trust I was formed in October 2007, by Whiting Petroleum Corporation. Immediately prior to the closing of this offering, Whiting Petroleum Corporation’s wholly-owned subsidiaries, Whiting Oil and Gas Corporation and Equity Oil Company, will convey a term net profits interest to the trust that represents the right to receive 90% of the net proceeds (calculated as described below) from Whiting’s interests in certain existing oil and natural gas producing properties after the effective date of the conveyance of the net profits interest to the trust, which we refer to as the “net profits interest.” The net profits interest will entitle the trust to receive 90% of the net proceeds from the sale of production of 9.04 MMBOE (which is equivalent to 8.14 MMBOE attributable to the net profits interest) of proved reserves, after which the trust will terminate. These producing properties are located primarily in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions of the United States. We refer to Whiting’s net interests in such producing properties, after deduction of all royalties and other burdens on production thereon existing as of the date of the conveyance of the net profits interest to the trust, as the “underlying properties”.

The underlying properties include interests in approximately 3,000 producing wells located in 173 fields in 14 states. As of September 30, 2007, the total proved reserves attributable to the underlying properties, as estimated in the reserve report, were 13.18 MMBOE with a pre-tax PV10% value of $243.5 million. All of these reserves were classified as proved developed producing reserves. For the month of September 2007, the average daily net production from these properties was approximately 4,508 BOE/d or 4,057 BOE/d attributable to the net profits interest and were approximately 55% oil and natural gas liquids and 45% natural gas. Based on the pre-tax PV10% value in the reserve report, Whiting operates approximately 60.6% of these properties. The underlying properties are located in mature fields and have established production profiles.

The net profits interest will terminate at the time when 9.04 MMBOE have been produced from the underlying properties and sold, which is the equivalent of 8.14 MMBOE in respect of the trust’s right to receive 90% of the net proceeds from such production pursuant to the net profits interest. The 9.04 MMBOE represents the proved reserves attributable to the underlying properties that the reserve report projects to be produced by December 31, 2017. However, the exact rate of production cannot be predicted with certainty and such amount may be produced before or after that date. Although it is not required to do so, Whiting plans to make capital expenditures at its sole expense for recompletions and development it deems attractive to increase production on the underlying properties without regard to the burden of the net profits interest on the underlying properties. These capital expenditures could potentially accelerate the production and sale of 9.04 MMBOE from the underlying properties.

The gross proceeds from the underlying properties used to calculate the net profits interest will be based on prices realized for oil, natural gas and natural gas liquids attributable to the underlying properties for each calendar quarter during the term of the net profits interest and calculated on an aggregate basis for all these properties. In calculating the net proceeds used to calculate the net profits interest, Whiting will deduct from the gross proceeds from oil and natural gas sales all royalties, lease operating expenses (including costs of workovers), production and property taxes, hedge payments made by Whiting to hedge contract counterparties, maintenance expenses, postproduction costs (including plugging and abandonment liabilities) and producing overhead, all calculated on an aggregate basis for all of these properties. These expenses and costs will be

reduced by hedge payments received by Whiting under the hedge contracts and other non-production revenue. However, if the hedge payments received by Whiting under the hedge contracts and other non-production revenue exceed the operating expenses during a quarterly period, the ability to use such excess amounts to offset operating expenses will be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period when the hedge payments and the other non-production revenue are less than such expenses. Capital expenditures for recompletions and development drilling will not be deducted from gross proceeds. For a more complete description of the calculation of net proceeds, see “Computation of Net Proceeds.”

Net proceeds payable to the trust will depend upon production quantities, sale prices of oil, natural gas and natural gas liquids, and costs to produce the oil, natural gas and natural gas liquids. If at any time costs should exceed gross proceeds, neither the trust nor the trust unitholders would be liable for the excess costs; the trust, however, would not receive any net proceeds until future net proceeds exceed the total of those excess costs, plus interest at the prevailing money market rate.

Whiting has entered into hedge contracts, which are structured as costless collar arrangements, to hedge approximately 80% of the anticipated production from the reserves attributable to the underlying properties in the reserve report for the period from January 1, 2008 through December 31, 2012 at prices ranging from $ to $ per Bbl of oil and at prices ranging from $ to $ per Mcf of natural gas. We refer to the hedge contracts to which Whiting is a party at the time of the closing of this offering that relate to the underlying properties as the “hedge contracts.” Whiting expects the hedge contracts will reduce the commodity price-related risks inherent in holding interests in oil and natural gas properties that have historically been characterized by significant price volatility, during the term of the hedge contracts, although they will also limit the potential for upside during the hedged period if oil and gas prices increase. As the hedge contracts cease to exist after 2012, unitholders’ exposure to fluctuations in commodity prices will increase. Under the terms of the conveyance, Whiting will be prohibited from entering into hedging arrangements covering the oil and natural gas production from the underlying properties following the completion of this offering.

The trust will make quarterly cash distributions of substantially all of its quarterly cash receipts of net proceeds attributable to the trust, after deduction of fees and expenses for the administration of the trust, to holders of its trust units during the term of the trust. The first quarterly distribution is expected to be made prior to or on February 29, 2008 to trust unitholders owning trust units on February 19, 2008. The trust’s first quarterly distribution will consist of an amount in cash paid by Whiting equal to the amount that would have been payable to the trust had the net profits interest been in effect during the period from October 1, 2007 through December 31, 2007. The second quarterly distribution is expected to be made prior to or on May 30, 2008 to trust unitholders owning trust units on May 20, 2008. The trust’s second quarterly distribution will consist of an amount in cash paid by Whiting equal to the amount that would have been payable to the trust had the net profits interest been in effect during the period from January 1, 2008 through the day prior to close of this offering plus the amount payable under the net profits interest for the period from the day of closing of the offering through March 31, 2008. The amount of quarterly cash distributions will be based on the cash attributable to the net profits interest that has been remitted by Whiting to the trustee with respect to the applicable quarter. Because the payments to the trust are on a cash basis and receipt of proceeds for natural gas sales typically lags a month behind those for oil sales, Whiting expects that the first quarterly distribution will include sales of oil for three months but sales of natural gas for only two months. Thereafter, quarterly distributions will generally include sales of both oil and natural gas for three months, with one month of the natural gas sales attributable to the prior quarter. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the underlying properties diminishing over time, a portion of each distribution will represent a return of your original investment.

The business and affairs of the trust will be managed by the trustee. Whiting has no ability to manage or influence the operations of the trust. The principal offices of the trustee are located at 919 Congress Avenue, Suite 500, Austin, Texas 78701, and its telephone number is (512) 236-6599.

Summary of Risk Factors

An investment in the trust units involves risks associated with fluctuation in energy commodity prices, the operation of the underlying properties, certain regulatory and legal matters, the structure of the trust and the tax characteristics of the trust units. The following list of factors is not exhaustive. Please read carefully these risks and other risks described under “Risk Factors.”


	•	The amounts of cash distributions by the trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquid prices, subject to the hedge contracts. The hedge contracts will limit the potential for increases in cash distributions due to oil and natural gas price increases during the first five years of the trust.

	•	Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the trust units.

	•	Financial returns to purchasers of trust units will vary based in part on how quickly 9.04 MMBOE are produced from the underlying properties and sold, and it is not known when that will occur.

	•	Risks associated with the production, gathering, transportation and sale of oil, natural gas and natural gas liquids could adversely affect cash distributions by the trust and the value of the trust units.

	•	The trust and the trust unitholders will have no voting or managerial rights with respect to the underlying properties. As a result, trust unitholders will have no ability to influence the operation of the underlying properties.

	•	Whiting has limited control over activities on certain of the underlying properties Whiting does not operate, which could reduce production from the underlying properties and cash available for distribution to trust unitholders.

	•	Shortages or increases in costs of oil field equipment, services and qualified personnel could reduce the amount of cash available for distribution.

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

	•	Whiting is not required to make capital expenditures on the underlying properties at historical levels or at all. If Whiting does not make capital expenditures, then the timing of production from the underlying properties may not be accelerated.

	•	Whiting may abandon individual wells or properties that it reasonably believes to be uneconomic.

	•	The reserves attributable to the underlying properties are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production.

	•	The amount of cash available for distribution by the trust will be reduced by the amount of any royalties, lease operating expenses, production and property taxes, maintenance expenses, postproduction costs and producing overhead, and payments made with respect to the hedge contracts.

	•	If the payments received by Whiting under the hedge contracts and certain other non-production revenue exceed operating expenses during a quarterly period, then the ability to use such excess amounts to offset operating expenses will be deferred until the next quarterly period when such amounts are less than such expenses.

	•	An increase in the differential between the NYMEX or other benchmark price of oil and natural gas and the wellhead price received could reduce cash distributions by the trust and the value of trust units.

	•	Under certain circumstances, the trust provides that the trustee may be required to sell the net profits interest and dissolve the trust prior to the expected termination of the trust. As a result, trust unitholders may not recover their investment.


	•	The disposal by Whiting of its remaining trust units may reduce the market price of the trust units.

	•	There has been no public market for the trust units and no independent appraisal of the value of the net profits interest has been performed.

	•	The market price for the trust units may not reflect the value of the net profits interest held by the trust.

	•	Conflicts of interest could arise between Whiting and the trust unitholders.

	•	The trust is managed by a trustee who cannot be replaced except at a special meeting of trust unitholders.

	•	Trust unitholders have limited ability to enforce provisions of the net profits interest.

	•	Courts outside of Delaware may not recognize the limited liability of the trust unitholders provided under Delaware law.

	•	The operations of the underlying properties may result in significant costs and liabilities with respect to environmental and operational safety matters, which could reduce the amount of cash available for distribution to trust unitholders.

	•	The operations of the underlying properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the cash distributions to the trust unitholders.

	•	The trust has not obtained a ruling from the IRS regarding the tax treatment of ownership of the trust units. If the IRS were to determine (and be sustained in that determination) that the trust is not a “grantor trust” for federal income tax purposes, or that the net profits interest is not a debt instrument for federal income tax purposes, the trust unitholders may receive different and less advantageous tax treatment than that described in this prospectus.

	•	The trust’s net profits interest may be characterized as an executory contract in bankruptcy, which could be rejected in bankruptcy, thus relieving Whiting from its obligations to make payments to the trust with respect to the net profits interest.

	•	If the financial position of Whiting degrades in the future, Whiting may not be able to satisfy its obligations to the trust.

	•	The trust’s receipt of payments based on the hedge contracts depends upon the financial position of the hedge contract counterparties and Whiting. A default by any of the hedge contract counterparties could reduce the amount of cash available for distribution to the trust unitholders.

Whiting Petroleum Corporation

Whiting is an independent oil and gas company engaged in acquisition, development, exploitation, production and exploration activities primarily in the Permian Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the United States. Since Whiting’s inception in 1980, Whiting has built a strong asset base and achieved steady growth through property acquisitions, development and exploration activities. Whiting’s common stock trades on the New York Stock Exchange under the symbol of “WLL.” Whiting’s principal executive offices are located at 1700 Broadway, Suite 2300, Denver, Colorado 80290-2300, and its telephone number is (303) 837-1661.

Structure of the Trust

The trust will issue units to Whiting prior to the completion of this offering, and Whiting Petroleum Corporation will sell approximately 78.3% of these units in this offering, or approximately a combined 90.0% if the underwriters’ option to purchase additional trust units from Whiting is exercised in full. The following chart shows the relationship of Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, Equity Oil Company, the trust and the trust unitholders, assuming no exercise of the underwriters’ option to purchase additional trust units.


(1)		Prior to the closing of this offering, Whiting Petroleum Corporation’s wholly-owned subsidiaries, Whiting Oil and Gas Corporation and Equity Oil Company, will convey the net profits interest to the trust in consideration for the issuance by the trust of units, which will be distributed as a dividend to Whiting Petroleum Corporation. Whiting Petroleum Corporation is offering trust units to the public pursuant to this offering. The underwriters may exercise their option to purchase up to trust units in the aggregate at the initial offering price, less the underwriting discounts and commissions, to cover over-allotments, if any, within 30 days of the date of this prospectus from Whiting Petroleum Corporation.

(2)		Represents Whiting Oil and Gas Corporation’s and Equity Oil Company’s interests in the underlying properties. For those underlying properties for which Whiting is designated as the operator and those it is not, these interests on average consist of an approximate 68.3% and 16.9%, respectively, working interest in the leasehold interests to which the underlying properties relate (and, after taking into account royalty interests and other non-working interests burdening this working interest, an approximate 55.9% and 14.0%, respectively, net revenue interest in the oil and natural gas properties to which the underlying properties relate).

The Underlying Properties

The underlying properties consist of Whiting’s net interests in certain of its oil and natural gas producing properties located primarily in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions of the United States, after deduction of all royalties and other burdens on production thereon. The underlying

properties include interests in approximately 3,000 producing oil and natural gas wells in 173 fields on 195,616 gross acres in 14 states. Whiting has acquired interests in these properties through various acquisitions that have occurred during its 27 year existence. For the month ended September 2007, the average daily net production from these properties was 4,508 BOE/d. Whiting’s interests in these properties require Whiting to bear its proportionate share, along with the other working interest owners, of the costs of development and operation of such properties. The net profits interest entitles the trust to receive 90% of the net proceeds from the sale of production of 9.04 MMBOE (which is equivalent to 8.14 MMBOE attributable to the net profits interest) of proved reserves during the term of the trust. The 9.04 MMBOE represents the proved reserves attributable to the underlying properties that the reserve report projects to be produced by December 31, 2017. As of September 30, 2007, proved reserves attributable to the underlying properties, as estimated in the reserve report, were 13.18 MMBOE with a pre-tax PV10% value of $243.5 million. The reserves attributable to the underlying properties include all reserves expected to be economically produced during the life of the properties, whereas the trust is entitled to only receive 90% of the net proceeds from the sale of production of oil, natural gas and natural gas liquids attributable to the underlying properties until the underlying properties have produced 9.04 MMBOE.

Whiting’s interest in the underlying properties after deducting the net profits interest entitles it to 10% of the net proceeds from the sale of production of oil, natural gas and natural gas liquids attributable to the underlying properties during the term of the net profits interest and all of the net proceeds thereafter. The trust units retained by Whiting, which represent 21.7% of the trust units following the closing of this offering, assuming no exercise of the underwriters’ option to purchase additional trust units, are subject to lock-up arrangements. See “Trust Units Eligible for Future Sale — Lock-up Agreements.” Whiting believes that its retained ownership interests in the underlying properties and its ownership of trust units, which together entitle Whiting to receive approximately 29.5% of the net proceeds from the underlying properties, assuming no exercise of the underwriters’ option to purchase additional trust units, will provide incentive to operate (or cause to be operated) the underlying properties in an efficient and cost-effective manner. In addition, Whiting has agreed to operate these properties as a reasonably prudent operator in the same manner that it would operate if these properties were not burdened by the net profits interest and Whiting has agreed to use commercially reasonable efforts to cause the other operators to operate these properties in the same manner.

Major Producing Areas

The following table summarizes the estimated proved reserves by region attributable to the net profits interest according to the reserve report, the corresponding pre-tax PV10% value as of September 30, 2007 and the average daily net production attributable to the net profits interest for the month of September 2007.


			Proved Reserves (1)														September 2007
												Pre-Tax					Average
												PV10%		% of Total			Daily Net
	Number of		Oil		Natural Gas		Total		% of Total			Value(2)(3)		Pre-Tax			Production
Region	Fields		(Mbbl)		(MMcf)		(MBOE)(2)		Reserves			(In millions)		PV10% Value			(BOE/d)

Rocky Mountains		65		2,571		2,567		2,999		36.8	%	$	83.9		42.3	%		1,285
Mid-Continent		54		1,559		10,300		3,276		40.2			70.7		35.6			1,623
Permian Basin		28		837		1,992		1,169		14.4			28.6		14.4			602
Gulf Coast		26		190		3,043		697		8.6			15.3		7.7			547

Total		173		5,157		17,902		8,141		100.0	%	$	198.5		100.0	%		4,057


(1)		The net profits interest entitles the trust to receive 90% of the net proceeds from the sale of production of 9.04 MMBOE from the underlying properties, taken as a whole. The allocation and makeup of such reserves among regions is from the reserve report and may not reflect the actual location and makeup from which reserves will be produced under the net profits interest.

(2)		The total proved reserves attributable to the underlying properties, as estimated in the reserve report, were 13.18 MMBOE with a pre-tax PV10% value of $243.5 million, although the net profits interest will terminate when 9.04 MMBOE have been produced. The amounts in the table reflect the trust’s 90% net profits interest in such reserves. Proved reserves reflected in the table above for the net profits interest are based


		on NYMEX oil and natural gas prices as of September 30, 2007 of $81.66 per Bbl of oil and $6.15 per Mcf of natural gas less field transportation, quality and basis differentials of $8.20 per Bbl of oil and $0.25 per Mcf of natural gas, resulting in field adjusted prices of $73.46 per Bbl of oil and $5.90 per Mcf of natural gas.

(3)		Pre-tax PV10% value may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Pre-tax PV10% value is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. However, as of September 30, 2007, no provision for federal or state income taxes has been provided because taxable income is passed through to the unitholders of the trust. Therefore, the standardized measure of discounted future net cash flows attributable to the net profits interest is equal to the pre-tax PV10% value. The pre-tax PV10% value and the standardized measure of discounted future net cash flows do not purport to present the fair value of the oil and natural gas reserves attributable to the net profits interest.

The underlying properties are located in several major onshore producing basins in the continental United States. Whiting believes this broad distribution provides a buffer against regional trends that may negatively impact production or prices. Based on the pre-tax PV10% value in the reserve report, approximately 60.6% of these properties were operated by Whiting. Based on September 2007 production attributable to the net profits interest, approximately 55% was oil and natural gas liquids and 45% was natural gas. These properties are located in mature fields and have established production profiles. However, production and distributions to the trust will decline over time.

Rocky Mountains Region. The underlying properties in the Rocky Mountains region are located in two distinct areas. The first, from which oil is primarily produced, includes the Williston Basin in North Dakota and Montana and the Bighorn and Powder River Basins of Wyoming and the second, from which natural gas is primarily produced, includes southwest Wyoming, Colorado and Utah. These properties include 65 fields of which Whiting operates wells in 33 of these fields. The major North Dakota fields in this region include Bell Field and Fryberg Field that produce from Tyler sandstone, Whiskey Joe Field that produces primarily from the Mississippian Madison zone and Davis Creek Field that produces from the Fryberg zone. In Montana, the major fields include the Bainville Field and Palomino Fields that produce primarily from the Nisku zone. The major Wyoming fields in this region include the Sage Creek Field in the Bighorn Basin that produces from the Tensleep and Madison zones and the Kiehl Field in the Powder River Basin, which produces from the Minnelusa formation and is under waterflood. The Ignacio Blanco Field is the major Colorado field in this region and produces from the Fruitland Coal zone. Average daily net production attributable to the net profits interest from these properties was 1,285 BOE/d for the month of September 2007 from 677 wells that will be burdened by the net profits interest.

Mid-Continent Region. The underlying properties in the Mid-Continent region are located in Arkansas, Oklahoma, Kansas and Michigan. These properties include 54 fields of which Whiting operates wells in 30 of these fields. The major Arkansas field in this region is the Magnolia Smackover Pool Unit, which is the largest single field in the underlying properties. The major fields and areas in Oklahoma are located in the Anadarko Basin and include Putnam Field, Mocane-Laverne Gas Area, Sho-Vel-Tum Field and Nobscot Northwest Field, which primarily produce from the Oswego, Hunton, Penn, Morrow, Red Fork and Cottage Grove zones. Case Field is the major Michigan field in the region and produces from the Silurian Niagaran zone. Average daily net production attributable to the net profits interest from these properties was 1,623 BOE/d for the month of September 2007 from 455 wells that will be burdened by the net profits interest.

Permian Basin Region. The Permian Basin Region of West Texas and New Mexico is one of the major hydrocarbon producing provinces in the continental United States. The underlying properties in the Permian Basin region are located in Texas and New Mexico. These properties include 28 fields of which Whiting operates wells in 10 of these fields. The major fields in this region include Iatan East Howard Field, which produces from the San Andres, Glorieta and Clearfork zones; the Fullerton Field, which is unitized and produces from the Clearfork zone; and Patricia Field, which produces from the Sprayberry and Fusselman zones. Average daily net production attributable to the net profits interest from these properties was 602 BOE/

d for the month of September 2007 from approximately 1,612 wells that will be burdened by the net profits interest.

Gulf Coast Region. The underlying properties in the Gulf Coast region are located in Texas, Louisiana, Mississippi and Alabama. These properties include 26 onshore fields of which Whiting operates wells in two of these fields. The major field in this region is the Mestena Grande Field located in Texas, which produces from the Queen City zone. Average daily net production attributable to the net profits interest from these properties was 547 BOE/d for the month of September 2007 from approximately 264 wells that will be burdened by the net profits interest.

Key Investment Considerations

The following are some key investment considerations related to the underlying properties, the net profits interest and the trust units:


	•	Strong Oil Pricing Fundamentals. Based on September 2007 production attributable to the net profits interest, approximately 55% was crude oil and natural gas liquids. Crude oil prices have increased substantially during the last several years, primarily due to increased demand for crude oil on a worldwide basis, especially from the developing economies in China and India, without a corresponding increase in crude oil production. In addition, geopolitical instability and military conflicts in certain significant oil producing nations have led to supply interruptions and increased uncertainty regarding the levels of future supplies of crude oil.

	•	Long Production Histories. The mature oil and natural gas properties comprising the underlying properties have established production profiles. Based on the reserve report, production attributable to the underlying properties is expected to decline at an average year over year rate of approximately 11% between 2008 and 2017.

	•	Proved Developed Producing Reserve Base. Proved developed producing reserves may be considered the most valuable and lowest risk category of reserves because production has already commenced and the reserves do not require significant future development costs. Proved developed producing reserves attributable to the underlying properties represented all of the discounted present value of estimated future net revenues from the underlying properties.

	•	Downside Price Protection During the First Five Years of the Trust. For the period from January 1, 2008 through December 31, 2012, Whiting has entered into costless collar arrangements to hedge approximately 80% of the anticipated production from the reserves attributable to the underlying properties at prices ranging from $ to $ per Bbl of oil and at prices ranging from $ to $ per Mcf of natural gas. Assuming production occurs as estimated by the reserve report, this would represent approximately 47% of the proved reserves attributable to the net profits interest. The hedge contracts are intended to provide returns to unitholders and reduce the fluctuations in cash distributions to unitholders resulting from fluctuations in crude oil and natural gas prices, which have been characterized by significant volatility.

	•	Diversified Well Locations. The underlying properties include interests in approximately 3,000 producing wells in 173 fields located in 14 states. As a result, the loss of production from any one well or group of wells is not likely to have a material adverse effect on the net proceeds from the sale of production that are allocable to the trust.

	•	Recognized Sponsor with a Successful Track Record and Experienced Management. Whiting Petroleum Corporation is an independent oil and gas company whose common stock is traded on the New York Stock Exchange under the symbol of “WLL.” Since its inception in 1980, Whiting has built a strong asset base and achieved steady growth through property acquisitions as well as development and exploration activities. Whiting’s management team averages over 25 years of experience in the oil and gas industry. Additionally, Whiting’s personnel have extensive operational experience in each of the core geographical areas in which the oil and natural gas properties comprising the underlying properties are located.


	•	Potential Upside from Drilling and Recompletions. Although it is not required to do so, Whiting plans to make capital expenditures for development and recompletions it deems attractive to increase production on the underlying properties. The costs of these capital expenditures would be borne by Whiting, and would not be allocated to the costs used to determine net proceeds under the net profits interest. These capital expenditures could potentially accelerate the production and sale of the 8.14 MMBOE of proved reserves attributable to the net profits interest and, accordingly, potentially accelerate cash distributions by the trust.

Summary of Proved Reserves

Summary of Proved Reserves of Underlying Properties and Net Profits Interest. The following table sets forth, as of September 30, 2007, certain estimated proved oil (including natural gas liquids) and natural gas reserves estimated future net revenues and the discounted present value thereof attributable to the underlying properties and the net profits interest, in each case derived from the reserve report. The reserve report was prepared by Cawley, Gillespie & Associates, Inc. in accordance with criteria established by the Securities and Exchange Commission, or SEC. Proved reserves reflected in the table below for the underlying properties and net profits interest are based on NYMEX oil and natural gas prices as of September 30, 2007 of $81.66 per Bbl of oil and $6.15 per Mcf of natural gas less field transportation, quality and basis differentials of $8.20 per Bbl of oil and $0.25 per Mcf of natural gas, resulting in field adjusted prices of $73.46 per Bbl of oil and $5.90 per Mcf of natural gas. Oil equivalents in the table are the sum of the Bbls of oil and natural gas liquids and the BOE of the stated Mcfs of natural gas, calculated on the basis that six Mcfs of natural gas is the energy equivalent of one Bbl of oil. The estimated future net revenues attributable to the net profits interest as of September 30, 2007, are net of the trust’s proportionate share of all estimated costs deducted from revenue pursuant to the terms of the conveyance creating the net profits interest and include only the reserves attributable to the underlying properties that are expected to be produced within the term of the net profits interest. A summary of the reserve report is included as Appendix A to this prospectus.


	Proved Reserve(1)
			Natural		Oil
	Oil		Gas		Equivalent		Estimated Future Net Revenues from Proved Reserves
	(MBbl)		(MMcf)		(MBOE)		Undiscounted		Discounted(2)
							(in thousands, except per unit data)

Underlying properties (100%)(3)		8,663		27,082		13,176	$	415,055	$	243,535
Underlying properties (attributable to the net profits interest)(4)		5,157		17,902		8,141	$	279,074	$	198,481
Net profits interest with cost reductions(5)		3,016		10,569		4,778	$	279,074	$	198,481
Amount per trust unit(6)							$		$


(1)		The net profits interest entitles the trust to receive 90% of the net proceeds from the sale of production of 9.04 MMBOE from the underlying properties, which equals 8.14 MMBOE.

(2)		The present values of estimated future net revenues for the underlying properties and the net profits interest were determined using a discount rate of 10% per annum. As of September 30, 2007, no provision for federal or state income taxes has been provided because taxable income is passed through to the unitholders of the trust. Therefore, the standardized measure of the underlying properties and the underlying properties attributable to the net profits interest equal their corresponding pre-tax PV10% values, which totaled $243.5 million and $198.5 million, respectively, as of September 30, 2007.

(3)		Reserve volumes and estimated future net revenues for the underlying properties reflect volumes and revenues attributable to the underlying properties.

(4)		Reflects 90% of the estimated proved reserves attributable to the underlying properties expected to be produced within the term of the net profits interest based on the reserve report. Estimated future net revenues from proved reserves takes into account future estimated costs that are deducted in calculating net proceeds.

(5)		Proved reserves for the net profits interest are calculated as (x) 90% of the estimated proved reserves of the underlying properties less (y) reserve quantities of a sufficient value to pay 90% of the future estimated


		costs that are deducted in calculating net proceeds. Accordingly, proved reserves for the net profits interest reflect quantities expected to be produced during the term of the net profits interest that are calculated after reductions for future costs and expenses based on price and cost assumptions used in the reserve estimates. Estimated future net revenues from proved reserves takes into account future estimated costs that are deducted in calculating net proceeds.


(6)		Assumes trust units outstanding.

Annual Production Attributable to Net Profits Interest. The following graph shows estimated production of total proved reserves attributable to the net profits interest during the term of the net profits interest based upon the pricing and other assumptions set forth in the reserve report. The net profits interest will terminate at the time when 9.04 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 8.14 MMBOE in respect of the trust’s right to receive 90% of the net proceeds from such reserves pursuant to the net profits interest). The reserve report projects that 9.04 MMBOE will have been produced from the underlying properties and sold by December 31, 2017, which reflects an average year over year decline rate of approximately 11% between 2008 and 2017. However, cash distributions to unitholders may decline at a faster rate than the rate of production due to fixed and semi-variable costs attributable to the underlying properties. Also, the exact rate of production cannot be predicted with certainty and such amount may be produced before or after that date. Although it is not required to do so, Whiting plans to make capital expenditures at its sole expense for recompletions and development it deems attractive to increase production on the underlying properties without regard to the burden of the net profits interest on the underlying properties. These capital expenditures could potentially accelerate the production and sale of 9.04 MMBOE from the underlying properties. The following graph does not include the impact of any such capital expenditures by Whiting.

Historical Results of the Underlying Properties

The selected financial data presented below should be read in conjunction with the audited statements of historical revenues and direct operating expenses and the unaudited statements of historical revenues and direct operating expenses of the underlying properties, the related notes and “Discussion and Analysis of Historical Results of the Underlying Properties” included elsewhere in this prospectus. The following table sets forth revenues, direct operating expenses and the excess of revenues over direct operating expenses relating to the underlying properties for the three years in the period ended December 31, 2006, and for the nine-month periods ended September 30, 2006 and 2007, derived from the underlying properties’ audited and unaudited statements of historical revenues and direct operating expenses included elsewhere in this prospectus. The unaudited statements were prepared on a basis consistent with the audited statements and, in the opinion of Whiting, include all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the revenues, direct operating expenses and the excess of revenues over direct operating expenses relating to the underlying properties for the periods presented. The historical financial information includes the results of acquisitions beginning on the following dates: Equity Oil Company, July 20, 2004; Permian Basin Properties, September 23, 2004; Institutional Partnership Interests, June 23, 2005; Celero Energy, LP, October 4, 2005; and Howard Energy, August 3, 2006.


	Year ended December 31,						Nine months ended September 30,
	2004		2005		2006		2006		2007
							(Unaudited)		(Unaudited)

Revenues:
Oil sales	$	30,539,666	$	43,498,823	$	53,232,066	$	41,058,591	$	41,148,501
Natural gas sales		23,460,243		36,135,271		31,397,455		24,193,531		20,736,595



Total revenues		53,999,909		79,634,094		84,629,521		65,252,122		61,885,096



Direct operating expenses:
Lease operating		10,854,433		16,180,693		21,912,702		15,687,225		16,952,622
Production tax		3,954,703		5,602,452		6,006,308		4,621,121		4,365,517



Total direct operating expenses		14,809,136		21,783,145		27,919,010		20,308,346		21,318,139



Excess of revenues over direct operating expenses	$	39,190,773	$	57,850,949	$	56,710,511	$	44,943,776	$	40,566,957

The following table provides oil and natural gas sales volumes, average sales prices and capital expenditures relating to the underlying properties for the three years in the period ended December 31, 2006, and for the nine-month periods ended September 30, 2006 and 2007. Sales volumes for natural gas liquids are included with oil sales since they were not material. There were no hedges or other derivative activity attributable to the underlying properties during such periods. The historical financial information includes the results of acquisitions beginning on the following dates: Equity Oil Company, July 20, 2004; Permian Basin Properties, September 23, 2004; Institutional Partnership Interests, June 23, 2005; Celero Energy, LP, October 4, 2005; and Howard Energy, August 3, 2006.


							Nine months ended
	Year ended December 31,						September 30,
	2004		2005		2006		2006		2007

Operating data:
Net production:
Oil (MBbls)		827		893		946		704		717
Natural gas (MMcf)		4,268		5,082		5,057		3,838		3,328
Total production (MBOE)		1,538		1,740		1,789		1,344		1,271


Oil (per Bbl)	$	36.95	$	48.72	$	56.24	$	58.32	$	57.42


Natural gas (per Mcf)	$	5.50	$	7.11	$	6.21	$	6.30	$	6.23


Drilling and development capital expenditures (in thousands)(1):	$	6,396	$	6,453	$	10,036	$	6,908	$	5,280


(1)		Whiting cannot provide any assurance that future capital expenditures will be consistent with historical levels.

Summary Projected Cash Distributions

The following table sets forth a projection of cash distributions to holders of trust units who own trust units as of the record date for the distribution related to oil, natural gas and natural gas liquid production for the first quarter of 2008 and continue to own those trust units through the record date for the cash distribution payable with respect to oil, natural gas and natural gas liquid production for the last quarter of 2008. The table also reflects the methodology for calculating the projected cash distribution. The cash distribution projections were prepared by Whiting for the twelve months ending December 31, 2008 on an accrual of production basis based on the hypothetical assumptions that are described below and in “Projected Cash Distributions — Significant Assumptions Used to Prepare the Projected Cash Distributions.” Actual cash distributions will be on a cash basis and may vary from those presented.

Whiting does not as a matter of course make public projections as to future sales, earnings, or other results. However, the management of Whiting has prepared the prospective financial information set forth below to present the projected cash distributions to the holders of the trust units based on the estimates and hypothetical assumptions described below. The accompanying prospective financial information was not prepared with a view toward public disclosure or with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of Whiting’s management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and the expected future financial performance of the net profits interest. However, this information is not fact and should not be relied upon as being indicative of future results, and readers of this prospects are cautioned not to place undue reliance on the prospective financial information.

Neither Whiting’s independent auditors, nor any other independent accountants, have compiled, examined, or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its

achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information.

In the view of Whiting’s management, the accompanying unaudited projected financial information was prepared on a reasonable basis and reflects the best currently available estimates and judgments of Whiting related to oil, natural gas and natural gas liquid production, operating expenses and capital expenses, based on:


	•	the oil, natural gas and natural gas liquid production estimates contained in the reserve report; and

	•	any royalties, lease operating expenses, production and property taxes, maintenance expenses, postproduction costs and producing overhead, and payments made and costs with respect to the hedge contracts for the twelve months ending December 31, 2008.

The projected financial information was also based on the hypothetical assumption that prices for oil, natural gas and natural gas liquids remain constant during the twelve months ending December 31, 2008, at a price that equals 80% of the NYMEX futures prices for oil and natural gas on , 2008, plus 20% of the Bloomberg consensus price forecasts on , 2008 for oil and natural gas for 2008. The NYMEX futures prices on , 2008 were $ per Bbl of oil and $ per Mcf of natural gas and the Bloomberg consensus price forecasts were $ per Bbl of oil and $ per Mcf of natural gas on , 2008, which equals blended prices of $ per Bbl of oil and $ Mcf of natural gas. Because there is no Bloomberg consensus price for natural gas liquids, Whiting used a hypothetical price equal to approximately 66% of the price used in the projected cash distribution table for oil, which is consistent with the historical pricing realized by Whiting for natural gas liquids and is the methodology used in the reserve report. These hypothetical prices were adjusted to take into account Whiting’s estimate of the basis differential (based on location and quality of the production) between published commodity prices and the prices actually received by Whiting. Actual prices paid for oil, natural gas and natural gas liquids expected to be produced from the underlying properties in 2008 will likely differ from these hypothetical prices due to fluctuations in the prices generally experienced with respect to the production of oil, natural gas and natural gas liquids, and such prices may be higher or lower than utilized for purposes of the projected financial information. For example, the published average monthly closing NYMEX crude oil spot price per Bbl was $66.12 for the nine months ended September 30, 2007, with the monthly closing prices ranging from $54.67 to $79.63 during such period. See “Risk Factors — The amounts of the cash distributions by the trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquid prices.”

Whiting utilized these production estimates, hypothetical oil, natural gas and natural gas liquid prices and cost estimates in preparing the projected financial information. This methodology is consistent with the requirements of the SEC for estimating oil, natural gas and natural gas liquid reserves and discounted present value of future net revenues attributable to the net profits interest, other than the use of the NYMEX futures prices for oil and natural gas on , 2008 and Bloomberg consensus price forecasts rather than the use of constant prices based on the prices in effect at the time of the reserve estimate as required by the rules and regulations of the SEC. The actual production amounts, commodity prices and costs for 2008, however, are not known for certain.

The projections and the estimates and hypothetical assumptions on which they are based are subject to significant uncertainties, many of which are beyond the control of Whiting or the trust. Actual cash distributions to trust unitholders, therefore, could vary significantly based upon events or conditions occurring that are different from the events or conditions assumed to occur for purposes of these projections. Cash distributions to trust unitholders will be particularly sensitive to fluctuations in oil, natural gas and natural gas liquid prices. See “Risk Factors — The amounts of the cash distributions by the trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquid prices” and “Projected Cash Distributions — Sensitivity of Projected Cash Distributions to Oil, Natural Gas and Natural Gas Liquid Production and Prices,” which shows projected effects on cash distributions from hypothetical changes in oil and natural gas prices. As a result of typical production declines for oil and natural gas properties, production estimates generally decrease from year to year, and the projected cash distributions shown in

the table below are not indicative of distributions for future years. See “Projected Cash Distributions — Sensitivity of Projected Cash Distributions to Oil, Natural Gas and Natural Gas Liquid Production and Prices,” which shows projected effects on cash distributions from hypothetical changes in oil and natural gas production. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the underlying properties diminishing over time, a portion of each distribution will represent a return of your original investment. Based on the reserve report, production attributable to the underlying properties is expected to decline at an average year over year rate of approximately 11% between 2008 and 2017. However, cash distributions to unitholders may decline at a faster rate than the rate of production due to fixed and semi-variable costs attributable to the underlying properties. See “Risk Factors — The reserves attributable to the underlying properties are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production.”


	Projection for Twelve Months Ending
	December 31, 2008, Based on Oil,
	Natural Gas and Natural Gas Liquid
Projected Cash Distributions	Production in Reserve Report(2)
	(dollars in thousands, except per Bbl, Mcf
	and per trust unit amounts)

Underlying properties sales volumes:
Oil and natural gas liquids (MBbls)
Natural gas (MMcf)
Assumed sales price:
Oil and natural gas liquids (per Bbl)	$
Natural gas (per Mcf)	$
Calculation of net proceeds:
Gross proceeds:
Oil and natural gas liquid sales	$
Natural gas sales
Payments made by Whiting to settle hedge contracts

Total	$

Costs:
Lease operating expenses	$
Production and property taxes
Payments received by Whiting to settle hedge contracts

Total	$

Net proceeds	$

Percentage allocable to net profits interest		90	%
Total cash proceeds to trust
Trust administrative expenses

Projected cash distribution on trust units	$

Projected cash distribution per trust unit(1)	$

Projected amount of cash distribution per trust unit that represents a return of capital(1)	$


(1)		Assumes trust units outstanding.

(2)		The cash distribution projections were prepared by Whiting on an accrual of production basis based on hypothetical assumptions. Actual cash distributions will be on a cash basis and may vary from those presented. For more information about the hypothetical assumptions made in preparing the table above, see “Projected Cash Distributions — Significant Assumptions Used to Prepare the Projected Cash Distributions.”

The Offering


Trust units offered by Whiting		units

Trust units outstanding		units

Use of proceeds		Whiting is offering all of the trust units to be sold in this offering and Whiting will receive all proceeds from the offering. Whiting intends to use the funds to repay a portion of the debt outstanding under its credit agreement. See “Use of Proceeds.”

Proposed NYSE symbol		WHX

Quarterly cash distributions		Actual cash distributions to the trust unitholders will depend upon the quantity of oil, natural gas and natural gas liquids produced and attributable to the underlying properties, the prices received for oil, natural gas and natural gas liquid production and other factors. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the underlying properties diminishing over time, a portion of each distribution will represent a return of your original investment. Oil, natural gas and natural gas liquid production from proved reserves attributable to the underlying properties is expected to decline over the term of the trust. See “Risk Factors.”

		It is expected that quarterly cash distributions during the term of the trust will be made by the trustee no later than 60 days following the end of each quarter (or the next succeeding business day) to the trust unitholders of record on the 50th day following the end of each quarter.

Net profits interest		The net profits interest will be conveyed to the trust out of Whiting’s interests in the underlying properties. The net profits interest will entitle the trust to receive 90% of the net proceeds during the term of the trust from the sale of production of oil, natural gas and natural gas liquids attributable to the underlying properties.

Termination of the trust		The net profits interest will terminate at the time when 9.04 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 8.14 MMBOE in respect of the trust’s right to receive 90% of the net proceeds from such reserves pursuant to the net profits interest), and the trust will soon thereafter wind up its affairs and terminate.

Net proceeds		The conveyance creating the net profits interest entitles the trust to receive an amount of cash for each quarter equal to 90% of the net proceeds from the sale of oil, natural gas and natural gas liquid production attributable to the underlying properties during the term of the net profits interest. In general, “gross proceeds” means the sales price received by Whiting from sales of oil, natural gas and natural gas liquids attributable to the underlying properties calculated on an aggregate basis for all these properties for each calendar quarter. “Net proceeds” equals the gross proceeds, less all royalties, lease operating expenses (including costs of workovers), production and property taxes, payments made by Whiting to hedge contract counterparties upon settlements of the hedge contracts, maintenance expenses, postproduction costs (including plugging


		and abandonment liabilities) and producing overhead, all calculated on an aggregate basis for all of these properties. These expenses and costs will be reduced by hedge payments received by Whiting under the hedge contracts and other non-production revenue. If the hedge payments received by Whiting under the hedge contracts and other non-production revenue exceed the operating expenses during a quarterly period, the ability to use such excess amounts to offset operating expenses will be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period when the hedge payments and the other non-production revenue are less than such expenses. Capital expenditures for recompletions and development drilling will not be deducted from gross proceeds. For a more detailed description of the determination of “net proceeds,” see “Computation of Net Proceeds.”

Administrative services fee payable to Whiting		Whiting will be entitled to receive an annual administrative services fee, payable quarterly, during the term of the trust, for providing accounting, bookkeeping and informational services relating to the net profits interest. The fee will total $200,000 per year. A more detailed description of the administrative services fee is set forth under the caption “The Trust — Administrative Services Fee.”

Summary of income tax consequences		Trust unitholders will be taxed directly on the income from assets of the trust. The net profits interest should be treated as a debt instrument for federal income tax purposes, and a trust unitholder in that event will be required to include in such trust unitholder’s income its share of the interest income on such debt instrument as it accrues in accordance with the rules applicable to contingent payment debt instruments contained in the Internal Revenue Code of 1986, as amended and the corresponding regulations, as well as such trust unitholder’s share of any income on the trust’s hedges. If the net profits interest is not treated as a debt instrument, then a trust unitholder would be allowed to recoup its basis in the net profits interest on a schedule that is in proportion to production from the net profits interest and that is more favorable to a trust unitholder than the schedule on which basis will be recovered if the net profits interest is treated as a debt instrument for federal income tax purposes. However, the deductions that would be allowed to an individual trust unitholder in that event may be itemized deductions, the deductibility of which would be subject to limitations that may or may not apply depending upon the trust unitholder’s circumstances. See “Federal Income Tax Consequences.”

Investing in Trust Units

Investing in these trust units differs from investing in corporate common stock because:


	•	trust unitholders are owed a fiduciary duty by the trustee, but not by Whiting;

	•	trust unitholders have limited voting rights;

	•	trust unitholders are taxed directly on their share of trust net income;

	•	substantially all trust income must be distributed to trust unitholders; and

	•	trust assets are limited to the net profits interest, which has a finite economic life.

RISK FACTORS

You should carefully consider each of the risks described below, together with all of the other information contained or incorporated by reference in this prospectus before deciding to invest in the trust units. If any of the following risks develop into actual events, the amount of cash available for distributions to trust unitholders and the value of the trust units could be reduced.

The amounts of cash distributions by the trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquid prices, subject to the hedge contracts. The hedge contracts will limit the potential for increases in cash distributions due to oil and natural gas price increases during the first five years of the trust.

The reserves attributable to the underlying properties and the quarterly cash distributions of the trust are highly dependent upon the prices realized from the sale of oil, natural gas and natural gas liquids. Prices of oil, natural gas and natural gas liquids can fluctuate widely on a quarter-to-quarter basis in response to a variety of factors that are beyond the control of the trust and Whiting. These factors include, among others:


	•	political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South America;

	•	weather conditions or force majeure events;

	•	levels of supply of and demand for oil, natural gas and natural gas liquids;

	•	U.S. and worldwide economic conditions;

	•	the price and availability of alternative fuels;

	•	the proximity to, and capacity of, refineries and gathering and transportation facilities; and

	•	energy conservation and environmental measures.

Moreover, government regulations, such as regulation of natural gas gathering and transportation and possible price controls, can affect commodity prices in the long term.

Recent oil prices have been high compared to historical prices. For example, the NYMEX crude oil spot prices per Bbl were $32.52, $43.45, $61.04 and $61.05 as of December 31, 2003, 2004, 2005 and 2006, respectively, and was $94.53 as of October 31, 2007. Additionally, natural gas prices have been volatile in the recent past. For example, natural gas prices based upon delivery at the Henry Hub in Louisiana were $6.19, $6.15, $9.52 and $5.52 as of December 31, 2003, 2004, 2005 and 2006, respectively, and was $7.28 as of October 31, 2007.

Whiting has entered into hedge contracts, which are structured as costless collar arrangements, that will hedge approximately 80% of the oil and natural gas volumes expected to be produced from the underlying properties through 2012. These hedge contracts, however, do not cover all of the oil and natural gas volumes that are expected to be produced during the term of the trust. Because of the differential between NYMEX or other benchmark prices of oil and natural gas and the wellhead price received, hedge contracts may not totally offset the effects of price fluctuations. Whiting has not entered into any hedge contracts relating to oil and natural gas volumes expected to be produced after 2012, and the terms of the conveyance of the net profits interest will prohibit Whiting from entering into new hedging arrangements following the completion of this offering. As a result, the amounts of the cash distributions may fluctuate significantly after 2012 as a result of changes in commodity prices because there will be no hedge contracts in place to reduce the effects of any changes in commodity prices. The hedge contracts may also limit the amount of cash available for distribution if prices increase. In addition, the hedge contracts are subject to counterparty nonperformance and other risks. For a discussion of the hedge contracts, see “The Underlying Properties — Hedge Contracts.”

Lower prices of oil, natural gas and natural gas liquids will reduce the amount of the net proceeds to which the trust is entitled and may ultimately reduce the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties. As a result, the operator of any of the underlying

properties could determine during periods of low commodity prices to shut in or curtail production from the underlying properties. In addition, the operator of these properties could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Because these properties are mature, decreases in commodity prices could have a more significant effect on the economic viability of these properties as compared to more recently discovered properties. The commodity price sensitivity of these mature wells is due to a culmination of factors that vary from well-to-well, including the additional costs associated with water handling and disposal, chemicals, surface equipment maintenance, downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result, the volatility of commodity prices may cause the amount of future cash distributions to trust unitholders to fluctuate, and a substantial decline in the price of oil, natural gas or natural gas liquids will reduce the amount of cash available for distribution to the trust unitholders.

Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the trust units.

The value of the trust units and the amount of future cash distributions to the trust unitholders will depend upon, among other things, the accuracy of the production and reserves estimated to be attributable to the underlying properties and the net profits interest. Estimating production and reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary both positively and negatively from estimates and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating production and reserves. Those factors and assumptions include:


	•	historical production from the area compared with production rates from other producing areas;

	•	the assumed effect of governmental regulation; and

	•	assumptions about future prices of oil, natural gas and natural gas liquids, including differentials, production and development expenses, gathering and transportation costs, severance and excise taxes and capital expenditures.

Changes in these assumptions can materially increase or decrease production and reserve estimates.

The estimated reserves attributable to the net profits interest and the estimated future net revenues attributable to the net profits interest are based on estimates of reserve quantities and revenues for the underlying properties. See “The Underlying Properties — Reserves” for a discussion of the method of allocating proved reserves to the underlying properties and the net profits interest. The quantities of reserves attributable to the underlying properties and the net profits interest may decrease in the future as a result of future decreases in the price of oil, natural gas or natural gas liquids.

Financial returns to purchasers of trust units will vary in part based on how quickly 9.04 MMBOE are produced from the underlying properties and sold, and it is not known when that will occur.

The net profits interest will terminate at the time when 9.04 MMBOE have been produced from the underlying properties and sold. The reserve report projects that 9.04 MMBOE will have been produced from the underlying properties and sold by December 31, 2017. However, the exact rate of production cannot be predicted with certainty and such amount may be produced before or after that date. If production attributable to the underlying properties is slower than estimated, then financial returns to purchasers of trust units will be lower assuming constant prices because cash distributions attributable to such production will occur at a later date.

Risks associated with the production, gathering, transportation and sale of oil, natural gas and natural gas liquids could adversely affect cash distributions by the trust and the value of the trust units.

The revenues of the trust, the value of the trust units and the amount of cash distributions to the trust unitholders will depend upon, among other things, oil, natural gas and natural gas liquid production and prices

and the costs incurred to exploit oil and natural gas reserves attributable to the underlying properties. Drilling, production or transportation accidents that temporarily or permanently halt the production and sale of oil, natural gas and natural gas liquids at any of the underlying properties will reduce trust distributions by reducing the amount of net proceeds available for distribution. For example, accidents may occur that result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any costs incurred in connection with any such accidents that are not insured against will have the effect of reducing the net proceeds available for distribution to the trust. In addition, curtailments or damage to pipelines used to transport oil, natural gas and natural gas liquid production to markets for sale could reduce the amount of net proceeds available for distribution. Any such curtailment or damage to the gathering systems could also require finding alternative means to transport the oil, natural gas and natural gas liquid production from the underlying properties, which alternative means could result in additional costs that will have the effect of reducing net proceeds available for distribution.

The trust and the trust unitholders will have no voting or managerial rights with respect to the underlying properties. As a result, trust unitholders will have no ability to influence the operation of the underlying properties.

Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners of oil and natural gas properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. Neither the trustee nor the trust unitholders have any contractual ability to influence or control the field operations of, sale of oil and natural gas from the underlying properties. Also, the trust unitholders have no voting rights with respect to the operators of these properties and, therefore, will have no managerial, contractual or other ability to influence the activities of the operators of these properties.

Whiting has limited control over activities on certain of the underlying properties Whiting does not operate, which could reduce production from the underlying properties and cash available for distribution to trust unitholders.

Whiting Oil and Gas Corporation is currently designated as the operator of approximately 60.6% of the underlying properties based on the pre-tax PV10% value contained in the reserve report. However, for the 39.4% of the underlying properties that Whiting does not operate, Whiting does not have control over normal operating procedures or expenditures relating to such properties. The failure of an operator to adequately perform operations or an operator’s breach of the applicable agreements could reduce production from the underlying properties and the cash available for distribution to trust unitholders. The success and timing of operational activities on properties operated by others therefore depends upon a number of factors outside of Whiting’s control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells, and use of technology. Because Whiting does not have a majority interest in most of the non-operated properties comprising the underlying properties, Whiting may not be in a position to remove the operator in the event of poor performance.

Shortages or increases in costs of oil field equipment, services and qualified personnel could reduce the amount of cash available for distribution.

The demand for qualified and experienced field personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other oilfield equipment as demand for rigs and equipment has increased along

with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could significantly decrease the amount of cash available for distribution to the trust unitholders, or restrict operations on the underlying properties.

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

Market conditions or a lack of satisfactory oil and natural gas transportation arrangements may hinder access to oil and natural gas markets or delay production. The availability of a ready market for 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. The ability to market production depends substantially on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third-parties. The failure to obtain such services on acceptable terms could materially reduce production from the underlying properties and the cash available for distribution to trust unitholders. Wells may be required to be shut in for a lack of a market or because access to natural gas pipelines, gathering systems or processing facilities may be limited or unavailable. If that were to occur, then production would be unrealized from those wells included in the underlying properties until production arrangements were made to deliver the production to market.

Whiting is not required to make capital expenditures on the underlying properties at historical levels or at all. If Whiting does not make capital expenditures, then the timing of production from the underlying properties may not be accelerated.

Whiting has made capital expenditures on the underlying properties in the amounts set forth in “The Underlying Properties — Historical Results of the Underlying Properties,” which have increased production from the underlying properties. Although Whiting plans to make capital expenditures for recompletions and development it deems attractive to increase production on the underlying properties without regard to the burden of the net profits interest on the underlying properties, Whiting has no contractual obligation to do so. In addition, some of the historical capital expenditures related to properties that Whiting recently acquired will no longer require historical levels of capital expenditures. Furthermore, for properties on which Whiting is not designated as the operator, the decision whether to make capital expenditures is made by the operator and Whiting has no control over the timing or amount of those capital expenditures. Whiting also has the right to non-consent and not participate in the capital expenditures on these properties, in which case Whiting and the trust will not receive the production resulting from such capital expenditures. Accordingly, it is likely that capital expenditures with respect to the underlying properties will vary from and may be less than historical levels.

Whiting may abandon individual wells or properties that it reasonably believes to be uneconomic.

Whiting will be required under the applicable conveyance to act as a reasonably prudent operator in the state where the underlying properties are located under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the net profits interest as a burden on such property. However, under such standards, Whiting may abandon any well if it reasonably believes that the well can no longer produce oil or natural gas in commercially economic quantities. This could result in termination of the net profits interest relating to the abandoned well.

The reserves attributable to the underlying properties are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production.

The net proceeds payable to the trust from the net profits interest are derived from the sale of oil, natural gas and natural gas liquids produced from the underlying properties and proceeds, if any, received by Whiting upon settlement of the hedge contracts. The reserves attributable to the underlying properties are depleting

assets, which means that the reserves attributable to the underlying properties will decline over time. As a result, the quantity of oil and natural gas produced from the underlying properties is expected to decline over time. Based on the reserve report, production attributable to the underlying properties is expected to decline at an average year over year rate of approximately 11% between 2008 and 2017. However, cash distributions to unitholders may decline at a faster rate than the rate of production due to fixed and semi-variable costs attributable to the underlying properties. Also, the anticipated rate of decline is an estimate and actual decline rates will likely vary from those estimated. The net profits interest will terminate at the time when 9.04 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 8.14 MMBOE in respect of the trust’s right to receive 90% of the net proceeds from such reserves pursuant to the net profits interest).

Future maintenance projects on the underlying properties beyond those which are currently estimated may affect the quantity of proved reserves that can be economically produced from the underlying properties. The timing and size of these projects will depend on, among other factors, the market prices of oil, natural gas and natural gas liquids. If operators of the underlying properties do not implement required maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by Whiting or estimated in the reserve report. In addition Whiting is not required to make any capital expenditures.

The trust agreement will provide that the trust’s business activities will be limited to owning the net profits interest and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyance related to the net profits interest. As a result, the trust will not be permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets and production attributable to the net profits interest.

Because the net proceeds payable to the trust are derived from the sale of depleting assets, the portion of the distributions to unitholders attributable to depletion should be considered a return of capital as opposed to a return on investment. Eventually, the net profits interest may cease to produce in commercial quantities and the trust may, therefore, cease to receive any distributions of net proceeds therefrom.

The amount of cash available for distribution by the trust will be reduced by the amount of any royalties, lease operating expenses, production and property taxes, maintenance expenses, postproduction costs and producing overhead, and payments made with respect to the hedge contracts.

Production costs on the underlying properties are deducted in the calculation of the trust’s share of net proceeds. In addition, production and property taxes and any costs or payments associated with post-production costs will be deducted in the calculation of the trust’s share of net proceeds. Accordingly, higher or lower production expenses, taxes and post-production costs will directly decrease or increase the amount received by the trust in respect of its net profits interest. For a summary of these costs for the last three years, see “The Underlying Properties.” Historical costs may not be indicative of future costs. The amount of net proceeds subject to the net profits interest will also be reduced by all payments made by Whiting to hedge contract counterparties upon settlement of the hedge contracts.

If production costs of the underlying properties and payments made by Whiting to hedge contract counterparties exceed the proceeds of production, the trust will not receive net proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest during the deficit period.

If the payments received by Whiting under the hedge contracts and certain other non-production revenue exceed operating expenses during a quarterly period, then the ability to use such excess amounts to offset operating expenses will be deferred until the next quarterly period when such amounts are less than such expenses.

If the hedge payments received by Whiting and certain other non-production revenue exceed the operating expenses during a quarterly period, the ability to use such excess amounts to offset operating expenses will be deferred until the next quarterly period when such amounts are less than such expenses. If such amounts are deferred, then the applicable quarterly distribution will be less than it would have otherwise been.

However, if any excess amounts have not been used to offset costs at the time when 9.04 MMBOE have been produced from the underlying properties and sold, which is the time when the net profits interest will terminate, then unitholders will not be entitled to receive the benefit of such excess amounts. Such a scenario could occur if oil and natural gas prices decline significantly during the first five years of the net profits interest and remained low for the remainder of the term.

An increase in the differential between the NYMEX or other benchmark price of oil and natural gas and the wellhead price received could reduce cash distributions by the trust and the value of trust units.

The prices received for our oil and natural gas production usually trade at a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the price received is called a differential. The differential may vary significantly due to market conditions, the quality and location of production and other factors. Whiting cannot accurately predict oil and natural gas differentials. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price received could reduce cash distributions by the trust and the value of the trust units.

Under certain circumstances, the trust provides that the trustee may be required to sell the net profits interest and dissolve the trust prior to the expected termination of the trust. As a result, trust unitholders may not recover their investment.

The trustee must sell the net profits interest if the holders of a majority of the trust units approve the sale or vote to dissolve the trust. The trustee must also sell the net profits interest if the annual gross proceeds attributable to the net profits interest are less than $1.0 million for each of any two consecutive years. The sale of the net profits interest will result in the dissolution of the trust. The net proceeds of any such sale will be distributed to the trust unitholders.

The net profits interest will terminate at the time when 9.04 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 8.14 MMBOE in respect of the trust’s right to receive 90% of the net proceeds from such reserves pursuant to the net profits interest). The trust unitholders will not be entitled to receive any net proceeds from the sale of production from the underlying properties following the termination of the net profits interest. Therefore, the market price of the trust units will likely diminish towards the end of the term of the net profits interest because the cash distributions from the trust will cease at the termination of such net profits interest and the trust will have no right to any additional production from the underlying properties after the term of the net profits interest.

The disposal by Whiting of its remaining trust units may reduce the market price of the trust units.

Whiting will own 21.7% of the trust units after this offering, or 10% if the underwriters’ option to purchase additional trust units is exercised in full. If Whiting sells these units, then the market price of the trust units may be reduced. See “Selling Trust Unitholder.” Whiting has entered into a lock-up agreement that prohibits it from selling any trust units for a period of 180 days after the date of this prospectus without the consent of Raymond James & Associates, Inc., acting as representative of the several underwriters. See “Underwriting.” In connection with the closing of this offering, Whiting and the trust intend to enter into a registration rights agreement pursuant to which the trust will agree to file a registration statement or shelf registration statement to register the resale of the remaining trust units held by Whiting and any transferee of the trust units upon request by such holders. See “Trust Units Eligible for Future Sale — Registration Rights.”

There has been no public market for the trust units and no independent appraisal of the value of the net profits interest has been performed.

The number of trust units to be delivered to Whiting in exchange for the net profits interest and the initial public offering price of the trust units will be determined by negotiation among Whiting and the underwriters. Among the factors to be considered in determining such number of trust units and the initial public offering price, in addition to prevailing market conditions, will be current and historical oil and natural gas prices,

current and prospective conditions in the supply and demand for oil and natural gas, reserve and production quantities estimated for the net profits interest and the trust’s estimated cash distributions. None of Whiting, the trust or the underwriters will obtain any independent appraisal or other opinion of the value of the net profits interest other than the reserve report prepared by Cawley, Gillespie & Associates, Inc.

The market price for the trust units may not reflect the value of the net profits interest held by the trust.

The trading price for publicly traded securities similar to the trust units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the trust will vary in response to numerous factors outside the control of the trust, including prevailing prices for sales of oil, natural gas and natural gas liquid production attributable to the underlying properties. Consequently, the market price for the trust units may not necessarily be indicative of the value that the trust would realize if it sold the net profits interest to a third-party buyer. In addition, such market price may not necessarily reflect the fact that since the assets of the trust are depleting assets, a portion of each cash distribution paid on the trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. As a result, distributions made to a unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the unitholder.

Conflicts of interest could arise between Whiting and the trust unitholders.

The interests of Whiting and the interests of the trust and the trust unitholders with respect to the underlying properties could at times differ. For example, Whiting has the right, subject to significant limitations as described herein, to cause the trust to release a portion of the net profits interest in connection with a sale of a portion of the oil and natural gas properties comprising the underlying properties to which such net profits interest relates. In such an event, the trust is entitled to receive its proportionate share of the proceeds from the sale attributable to the net profits interest released. See “The Underlying Properties — Abandonment of Underlying Properties.” Except for specified matters that require approval of the trust unitholders described in “Description of the Trust Agreement,” the documents governing the trust do not provide a mechanism for resolving these conflicting interests.

The trust is managed by a trustee who cannot be replaced except at a special meeting of trust unitholders.

The business and affairs of the trust will be managed by the trustee. The voting rights of a trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for an annual or other periodic re-election of the trustee. The trust agreement provides that the trustee may only be removed and replaced by the holders of a majority of the outstanding trust units at a special meeting of trust unitholders called by either the trustee or the holders of not less than 10% of the outstanding trust units. Immediately following the closing of this offering, Whiting will own approximately 21.7% of the outstanding trust units (or 10% if the underwriters exercise in full their option to purchase up to an additional trust units from Whiting). As a result, it may be difficult to remove or replace the trustee without the approval of Whiting.

Trust unitholders have limited ability to enforce provisions of the net profits interest.

The trust agreement permits the trustee to sue Whiting on behalf of the trust to enforce the terms of the conveyance creating the net profits interest. If the trustee does not take appropriate action to enforce provisions of the conveyance, your recourse as a trust unitholder would be limited to bringing a lawsuit against the trustee to compel the trustee to take specified actions. The trust agreement expressly limits the trust unitholders’ ability to directly sue Whiting or any other third party other than the trustee. As a result, the unitholders will not be able to sue Whiting to enforce these rights.

Courts outside of Delaware may not recognize the limited liability of the trust unitholders provided under Delaware law.

Under the Delaware Statutory Trust Act, trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of private corporations under the General Corporation Law of the State of Delaware. Courts in jurisdictions outside of Delaware, however, may not give effect to such limitation.

The operations of the underlying properties may result in significant costs and liabilities with respect to environmental and operational safety matters, which could reduce the amount of cash available for distribution to trust unitholders.

Significant costs and liabilities can be incurred as a result of environmental and safety requirements applicable to the oil and natural gas exploration, development and production activities of the underlying properties. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws, regulations, and enforcement policies, which legal requirements have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts on the operations of the underlying properties.

Strict, joint and several liability may be imposed under certain environmental laws and regulations, which could result in liability for the conduct of others or for the consequences of one’s own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If it were not possible to recover the resulting costs for such liabilities or non-compliance through insurance or increased revenues, then these costs could have a material adverse effect on the cash distributions to the trust unitholders. Please read “The Underlying Properties — Environmental Matters and Regulation” for more information.

The operations of the underlying properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the cash distributions to the trust unitholders.

The development and production operations of the underlying properties are subject to complex and stringent laws and regulations. In order to conduct the operations of the underlying properties in compliance with these laws and regulations, Whiting and the other operators must obtain and maintain numerous permits, approvals and certificates from various federal, state, local and governmental authorities. Whiting and the other operators may incur substantial costs and experience delays in order to maintain compliance with these existing laws and regulations, which could decrease the cash distributions to the trust unitholders. In addition, the costs of compliance may increase or the operations of the underlying properties may be otherwise adversely affected if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to such operations. Such costs could have a material adverse effect on the cash distributions to the trust unitholders.

The operations of the underlying properties are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on the cash distributions to the trust unitholders. Please read “The Underlying Properties — Environmental Matters and Regulation.”

The trust has not requested a ruling from the IRS regarding the tax treatment of ownership of the trust units. If the IRS were to determine (and be sustained in that determination) that the trust is not a “grantor trust” for federal income tax purposes, or that the net profits interest is not a debt instrument for federal income tax purposes, the trust unitholders may receive different and less advantageous tax treatment from that described in this prospectus.

If the net profits interest were not treated as a debt instrument, the deductions allowed to an individual trust unitholder in their recovery of basis in the net profits interest may be itemized deductions, the deductibility of which would be subject to limitations that may or may not apply depending upon the unitholder’s circumstances. See “Federal Income Tax Consequences.”

Neither Whiting nor the trustee has requested a ruling from the IRS regarding these tax questions, and neither Whiting nor the trust can assure you that such a ruling would be granted if requested or that the IRS will not challenge this position on audit.

Trust unitholders should be aware of the possible state tax implications of owning trust units. See “State Tax Considerations.”

The trust’s net profits interest may be characterized as an executory contract in bankruptcy, which could be rejected in bankruptcy, thus relieving Whiting from its obligations to make payments to the trust with respect to the net profits interest.

Whiting will record the conveyance of the net profits interest in the states where the underlying properties are located in the real property records in each county where these properties are located. Oil and natural gas leases are real property interests under the laws of the states where the underlying properties are located. The net profits interest is a non-operating, non-possessory interest carved out of the oil and natural gas leasehold estate, but certain jurisdictions have not directly determined whether a net profits interest is a real or a personal property interest. Whiting believes that the delivery and recording of the conveyance will constitute a fully conveyed and vested property interest in the trust under the applicable state’s laws. If in a bankruptcy proceeding in which Whiting becomes involved as a debtor a determination were made that the conveyance constitutes an executory contract and the net profits interest is not a fully conveyed property interest under the laws of the applicable state, and if such contract were not to be assumed in a bankruptcy proceeding involving Whiting, the trust would be treated as an unsecured creditor of Whiting with respect to such net profits interest in the pending bankruptcy proceeding. Please read “The Underlying Properties — Title to Properties” for more information.

If the financial position of Whiting degrades in the future, Whiting may not be able to satisfy its obligations to the trust.

Whiting operates approximately 60.6% of the underlying properties based on the pre-tax PV10% value. The conveyance provides that Whiting will be obligated to market, or cause to be marketed, the production related to underlying properties for which it operates. In addition, Whiting is obligated to use the proceeds it receives upon the settlement of the hedge contracts to offset operating expenses relating to the underlying properties, with certain restrictions, as discussed in more detail in “Computation of Net Proceeds.”

Whiting has entered into hedge contracts, consisting of costless collar arrangements, with institutional counterparties to reduce the exposure of the revenue from oil and natural gas production from the underlying properties to fluctuations in crude oil and natural gas prices in order to achieve more predictable cash flow. The crude oil and natural gas collar arrangements will settle based on the average of the settlement price for each commodity business day in the contract period. In a collar arrangement, the counterparty is required to make a payment to Whiting for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. Whiting is required to make a payment to the counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price. For a detailed description of the terms of these hedge contracts, please read “The Underlying Properties — Hedge Contracts.”

The ability of Whiting to perform its obligations related to the operation of the underlying properties, its obligations to counterparties related to the hedge contracts and its obligations to the trust with respect to the hedge contracts will depend on Whiting’s future financial condition and economic performance, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and upon financial, business and other factors, many of which are beyond the control of Whiting. See “Where You Can Find More Information” in this prospectus for information about the documents Whiting incorporates by reference into this prospectus that contain additional information relating to Whiting, including information relating to the business of Whiting, historical financial statements of Whiting and other financial information relating to Whiting.

The trust’s receipt of payments based on the hedge contracts depends upon the financial position of the hedge contract counterparties and Whiting. A default by any of the hedge contract counterparties could reduce the amount of cash available for distribution to the trust unitholders.

In the event that any of the counterparties to the hedge contracts default on their obligations to make payments to Whiting under the hedge contracts, the cash distributions to the trust unitholders would likely be materially reduced as the hedge payments are intended to provide additional cash to the trust during periods of lower crude oil and natural gas prices.

FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements about Whiting and the trust that are subject to risks and uncertainties. All statements other than statements of historical fact included in this document, including, without limitation, statements under “Prospectus Summary” and “Risk Factors” regarding the financial position, business strategy, production and reserve growth, and other plans and objectives for the future operations of Whiting and the trust are forward-looking statements. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Forward-looking statements are subject to risks and uncertainties and include statements made in this prospectus under “Projected Cash Distributions,” statements pertaining to operational activities and costs, and other statements in this prospectus that are prospective and constitute forward-looking statements.

When used in this document, the words “believes,” “expects,” “anticipates,” “projects,” “intends” or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this prospectus, could affect the future results of the energy industry in general, and Whiting and the trust in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:


	•	the effect of changes in commodity prices and conditions in the capital markets;

	•	uncertainty of estimates of oil and natural gas reserves and production;

	•	risks incident to the operation of oil and natural gas wells;

	•	future production costs;

	•	the inability to access oil and natural gas markets due to market conditions or operational impediments;

	•	failure of the underlying properties to yield oil or natural gas in commercially viable quantities;

	•	the effect of existing and future laws and regulatory actions;

	•	competition from others in the energy industry;

	•	risks arising out of the hedge contracts; and

	•	inflation.

This prospectus describes other important factors that could cause actual results to differ materially from expectations of Whiting and the trust, including under the heading “Risk Factors.” All written and oral forward-looking statements attributable to Whiting or the trust or persons acting on behalf of Whiting or the trust are expressly qualified in their entirety by such factors.

USE OF PROCEEDS

Prior to the closing of this offering, Whiting Petroleum Corporation’s wholly-owned subsidiaries, Whiting Oil and Gas Corporation and Equity Oil Company, will convey the net profits interest to the trust in consideration for the issuance by the trust of trust units, which will be distributed as a dividend to Whiting Petroleum Corporation. Whiting will pay underwriting discounts and expenses of approximately $ million associated with this offering and will receive all net proceeds from the offering. The estimated net proceeds to Whiting will be approximately $ million, assuming an offering price of $ per trust unit, and will increase to approximately $ million if the underwriters exercise their option to purchase additional trust units in full. Whiting intends to use the net proceeds from this offering to repay a portion of the debt outstanding under its credit agreement. Borrowings under its credit agreement had a weighted average interest rate of 6.4% as of September 30, 2007 and mature in August 2010.

THE TRUST

The trust is a statutory trust created under the Delaware Statutory Trust Act in October 2007. The business and affairs of the trust will be managed by The Bank of New York Trust Company, N.A., as trustee. Whiting has no ability to manage or influence the operations of the trust. In addition, Wilmington Trust Company will act as Delaware trustee of the trust. The Delaware trustee will have only minimal rights and duties as are necessary to satisfy the requirements of the Delaware Statutory Trust Act. In connection with the completion of this offering, Whiting Petroleum Corporation’s wholly-owned subsidiaries, Whiting Oil and Gas Corporation and Equity Oil Company, will convey the net profits interest to the trust in consideration for the issuance by the trust of trust units, which will be distributed as a dividend to Whiting Petroleum Corporation. The first quarterly distribution is expected to be made on or prior to February 29, 2008 to trust unitholders owning trust units on February 19, 2008. The trust’s first quarterly distribution will consist of an amount in cash paid by Whiting equal to the amount that would have been payable to the trust had the net profits interest been in effect during the period from October 1, 2007 through December 31, 2007. The trust’s second quarterly distribution will consist of an amount in cash paid by Whiting equal to the amount that would have been payable to the trust had the net profits interest been in effect during the period from January 1, 2008 through the day prior to close of this offering plus the amount payable under the net profits interest for the period from the day of closing of the offering through March 31, 2008.

The trustee can authorize the trust to borrow money to pay trust administrative or incidental expenses that exceed cash held by the trust. The trustee may authorize the trust to borrow from the trustee as a lender provided the terms of the loan are fair to the trust unitholders. The trustee may also deposit funds awaiting distribution in an account with itself, if the interest paid to the trust at least equals amounts paid by the trustee on similar deposits, and make other short-term investments with the funds distributed to the trust.

The trust will pay the trustee an administrative fee of $160,000 per year. The trust will pay the Delaware trustee a fee of $3,500 per year. The trust will also incur legal, accounting, tax and engineering fees, printing costs and other expenses that are deducted by the trust before distributions are made to trust unitholders. Total administrative expenses of the trust for 2008 are expected to be approximately $900,000, including the administrative services fee payable to Whiting.

Administrative Services Agreement

In connection with the closing of this offering, the trust has entered into an administrative services agreement with Whiting that obligates the trust, throughout the term of the trust, to pay to Whiting each quarter an administrative services fee for accounting, bookkeeping and informational services to be performed by Whiting on behalf of the trust relating to the net profits interest. The annual fee, payable in equal quarterly installments, will total $200,000. The administrative services agreement will terminate upon the termination of the net profits interest unless earlier terminated by mutual agreement of the trustee and Whiting.

PROJECTED CASH DISTRIBUTIONS

Immediately prior to the closing of this offering, Whiting will create the term net profits interest through a conveyance to the trust of a term net profits interest carved from Whiting’s interests in certain oil and natural gas producing properties, which properties are located primarily in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions of the United States. The net profits interest will entitle the trust to receive 90% of the net proceeds from the sale of production of oil, natural gas and natural gas liquids attributable to the underlying properties until the time when 9.04 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 8.14 MMBOE in respect of the trust’s right to receive 90% of the net proceeds from such reserves pursuant to the net profits interest).

The amount of trust revenues and cash distributions to trust unitholders will depend on, among other things:


	•	oil prices and natural gas prices;

	•	the volume of oil, natural gas and natural gas liquids produced and sold;

	•	the settlement prices of the hedge contracts;

	•	property and production taxes;

	•	production and post-production costs; and

	•	administrative expenses of the trust.

Projected Cash Distributions

The following table sets forth a projection of cash distributions on a quarterly and annual basis to holders of trust units who own trust units as of the record date for the distribution related to oil, natural gas and natural gas liquid production for the first quarter of 2008 and continue to own those trust units through the record date for the cash distribution payable with respect to oil, natural gas and natural gas liquid production for the last quarter of 2008. The table also reflects the methodology for calculating the projected cash distribution. The cash distribution projections were prepared by Whiting for each of the four quarters in 2008 and the twelve months ending December 31, 2008, on an accrual of production basis based on the hypothetical assumptions that are described in “— Significant Assumptions Used to Prepare the Projected Cash Distributions” below. Actual cash distributions will be on a cash basis and may vary from those presented.


	•	the oil, natural gas and natural gas liquid production estimates contained in the reserve report; and

	•	any royalties, lease operating expenses, production and property taxes, maintenance expenses, postproduction costs and producing overhead, and payments made and costs with respect to the hedge contracts for the twelve months ending December 31, 2008.

The projected financial information was also based on the hypothetical assumption that prices for oil, natural gas and natural gas liquids remain constant during the twelve months ending December 31, 2008, at a price that equals 80% of the NYMEX futures prices for oil and natural gas on , 2008 plus 20% of the Bloomberg consensus price forecasts on , 2008 for oil and natural gas for 2008. The NYMEX futures prices on , 2008 were $ per Bbl of oil and $ per Mcf of natural gas and the Bloomberg consensus price forecasts were $ per Bbl of oil and $ per Mcf of natural gas on , 2008, which equals blended prices of $ per Bbl of oil and $ Mcf of natural gas. Because there is no hedge in place or Bloomberg consensus price for natural gas liquids, Whiting used a hypothetical price equal to approximately 66% of the price used in the projected cash distribution table for oil, which is consistent with the historical pricing realized by Whiting for natural gas liquids and is the methodology used in the reserve report. These hypothetical prices were adjusted to take into account Whiting’s estimate of the basis differential (based on location and quality of the production) between published commodity prices and the prices actually received by Whiting. Actual prices paid for oil, natural gas and natural gas liquids expected to be produced from the underlying properties in 2008 will likely differ from these hypothetical prices due to fluctuations in the prices generally experienced with respect to the production of oil, natural gas and natural gas liquids, and such prices may be higher or lower than utilized for purposes of the projected financial information. For example, the published average monthly closing NYMEX crude oil spot price per Bbl was $66.12 for the nine months ended September 30, 2007, with the monthly closing prices ranging from $54.67 to $79.63 during such period. See “Risk Factors — The amounts of the cash distributions by the trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquid prices.”

The projections and the estimates and hypothetical assumptions on which they are based are subject to significant uncertainties, many of which are beyond the control of Whiting or the trust. Actual cash distributions to trust unitholders, therefore, could vary significantly based upon events or conditions occurring that are different from the events or conditions assumed to occur for purposes of these projections. Cash distributions to trust unitholders will be particularly sensitive to fluctuations in oil, natural gas and natural gas liquid prices. See “Risk Factors — The amounts of the cash distributions by the trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquid prices” and “Projected Cash Distributions — Sensitivity of Projected Cash Distributions to Oil, Natural Gas and Natural Gas Liquid Production and Prices,” which shows projected effects on cash distributions from hypothetical changes in oil and natural gas prices. As a result of typical production declines for oil and natural gas properties, production estimates generally decrease from year to year, and the projected cash distributions shown in the table below are not indicative of distributions for future years. See “— Sensitivity of Projected Cash Distributions to Oil, Natural Gas and Natural Gas Liquid Production and Prices” below, which shows projected

effects on cash distributions from hypothetical changes in oil and natural gas production. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the underlying properties diminishing over time, a portion of each distribution will represent a return of your original investment. Based on the reserve report, production attributable to the underlying properties is expected to decline at an average year over year rate of approximately 11% between 2008 and 2017. However, cash distributions to unitholders may decline at a faster rate than the rate of production due to fixed and semi-variable costs attributable to the underlying properties. See “Risk Factors — The reserves attributable to the underlying properties are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production.”

Projected Cash Distributions, Based on Oil, Natural Gas and Natural Gas Liquid
Production in Reserve Report(1)


	Quarter Ending												Year Ending
	March 31,			June 30,			September 30,			December 31,			December 31,
	2008			2008			2008			2008			2008
	(dollars in thousands, except per Bbl, Mcf and trust unit amounts)

Underlying properties sales volumes:
Oil and natural gas liquids (MBbls)
Natural gas (MMcf)
Assumed sales price:
Oil and natural gas liquids (per Bbl)	$			$			$			$			$
Natural gas (per Mcf)	$			$			$			$			$
Calculation of net proceeds:
Gross proceeds:
Oil and natural gas liquid sales	$			$			$			$			$
Natural gas sales
Payments made by Whiting to settle hedge contracts

Total	$			$			$			$			$

Costs
Lease operating expenses	$			$			$			$			$
Production and property taxes
Payments received by Whiting to settle hedge contracts

Total	$			$			$			$			$

Net proceeds	$			$			$			$			$

Percentage allocable to net profits interest		90	%		90	%		90	%		90	%		90	%

Total cash proceeds to trust

Trust administrative expenses

Projected cash distribution on trust units	$			$			$			$			$

Projected cash distribution per trust unit(2)	$			$			$			$			$

Projected amount of cash distribution per trust unit that represents a return of capital(2)	$			$			$			$			$


(1)		The cash distribution projections were prepared by Whiting on an accrual of production basis based on hypothetical assumptions. Actual cash distributions will be on a cash basis and may vary from those presented. For more information about the hypothetical assumptions made in preparing the table above, see “— Significant Assumptions Used to Prepare the Projected Cash Distributions” below.

(2)		Assumes trust units outstanding.

Sensitivity of Projected Cash Distributions to Oil, Natural Gas and Natural Gas Liquid Production and Prices

The amount of revenues of the trust and cash distributions to the trust unitholders will be directly dependent on the sales price for oil, natural gas and natural gas liquid production sold from the underlying properties, the volumes of oil, natural gas and natural gas liquids produced attributable to the underlying properties, payments made under the hedge contracts and, to some degree, the level of variations in lease operating expenses and production and property taxes. The tables below demonstrate the projected effect that hypothetical changes in the estimated oil and natural gas prices for 2008 and oil and natural gas production for 2008, as reflected in the reserve report, could have on cash distributions to the trust unitholders.

The tables and discussion below sets forth sensitivity analyses of annual cash distributions per trust unit for the twelve months ending December 31, 2008, on the accrual basis, on the assumption that a trust unitholder purchased a trust unit on January 1, 2008, and held such trust unit until the quarterly record date for distributions made with respect to oil, natural gas and natural gas liquid production in the last quarter of 2008, based upon (1) the assumption that a total of trust units are issued and outstanding after the closing of the offering made hereby; (2) an assumed purchase price of $ per trust unit; (3) various realizations of production levels estimated in the reserve report; (4) the hypothetical commodity prices based upon the NYMEX futures prices for oil and natural gas on , 2008 and Bloomberg consensus price forecasts for oil and natural gas on , 2008; (5) the impact of the hedge contracts entered into by Whiting that relate to production from the underlying properties; and (6) other assumptions described below under “— Significant Assumptions Used to Prepare the Projected Cash Distributions.” The hypothetical commodity prices of oil, natural gas and natural gas liquid production shown have been chosen solely for illustrative purposes. For a description of the effect of calculating annual cash distributions on an accrual basis rather than on a cash basis as prescribed in the conveyance of the net profits interest, see “— Significant Assumptions Used to Prepare the Projected Cash Distributions — Timing of Actual Distributions.”

The tables below are not a projection or forecast of the actual or estimated results from an investment in the trust units. The purpose of the tables below is to illustrate the sensitivity of cash distributions to changes in oil and natural gas production levels and changes in oil and natural gas prices. There is no assurance that the hypothetical assumptions described below will actually occur or that production or price levels will not change by amounts different from those shown in the tables.

Whiting has entered into certain hedge contracts related to the oil and natural gas production from the underlying properties for the period from January 1, 2008 through December 31, 2012. These hedge contracts are costless collar arrangements that hedge approximately 80% of the anticipated production attributable to the underlying properties at prices ranging from $ to $ per Bbl of oil and at prices ranging from $ to $ per Mcf of natural gas. Whiting will not enter into any hedge contracts related to production from the underlying properties for periods after 2012 and, therefore, cash distributions for those periods are expected to fluctuate significantly as a result of changes in oil and natural gas prices after that time. See “Risk Factors” for a discussion of various items that could impact production levels and the prices of oil and natural gas.

The purpose of the table below is to illustrate the sensitivity of cash distributions to changes in oil and natural gas production levels, excluding the impact of any price differences for production of oil and natural gas from the prices forecasted. The table below is not a projection or forecast of the actual or estimated results from an investment in the trust units.

Sensitivity of Total 2008 Projected Cash Distributions Per Trust Unit to Changes in Natural Gas
and Oil Production


Percentage of 2008		Total 2008 Projected
Estimated Oil and		Cash Distributions
Natural Gas Production(1)		Per Trust Unit

90%		$
95%		$
100%		$
105%		$
110%		$


(1)		Estimated production is based on the reserve report and the sensitivity analysis assumes that oil and natural gas production will continue to represent the same percentage of total production as estimated for 2008 in the reserve report.

The purpose of the table below is to illustrate the sensitivity of cash distributions to changes in oil and natural gas prices, excluding the impact of any differences in the amount of production of oil and natural gas as estimated in the reserve report. The table below is not a projection or forecast of the actual or estimated results from an investment in the trust units.

Sensitivity of Total 2008 Projected Cash Distributions Per Trust Unit to Changes in Natural Gas
and Oil Prices


Percentage of 2008		Total 2008 Projected
Estimated Oil and		Cash Distributions
Natural Gas Price(1)		Per Trust Unit

90%		$
95%		$
100%		$
105%		$
110%		$


(1)		Estimated prices are based on a price that equals 80% of the NYMEX futures prices for oil and natural gas on , 2008 plus 20% of the Bloomberg consensus price forecasts on , 2008 for oil and natural gas for 2008. The NYMEX futures prices on , 2008 were $ per Bbl of oil and $ per Mcf of natural gas and the Bloomberg consensus price forecasts were $ per Bbl of oil and $ per Mcf of natural gas on , 2008, which equals blended prices of $ per Bbl of oil and $ per Mcf of natural gas.

Significant Assumptions Used to Prepare the Projected Cash Distributions

Timing of Actual Distributions. In preparing the projected cash distributions and sensitivity analysis above, the revenues and expenses of the trust were calculated based on the terms of the conveyance creating the trust’s net profits interest. These calculations are described under “Computation of Net Proceeds — Net Profits Interest,” except that amounts for the projection and table above were calculated on an accrual of production basis rather than the cash basis prescribed by the conveyance. As a result of cash basis, the proceeds for production for a portion of the three months ended December 31, 2007 will actually enter into the calculation of net proceeds to be received by the trust in 2008. Net proceeds from production during the three months ended December 31, 2007, will in fact be distributed to the trust in 2008.

Production Estimates. Production estimates for 2008 are based on the reserve report. The reserve report assumed constant prices at September 30, 2007, based on a crude oil price of $81.66 ($73.46 field adjusted) per Bbl, a natural gas price of $6.15 ($5.90 field adjusted) per Mcf and the natural gas liquid price of $47.82 per Bbl. Production from the underlying properties for 2008 is estimated to be 791.6 MBbls of oil, 3,316.1 MMcf of natural gas and 45.1 MBbls of natural gas liquids. See “— Oil, Natural Gas and Natural Gas Liquid Prices” below for a description of changes in production due to price variations. Net sales for the nine months ended September 30, 2007, on an accrual basis, were 667.1 MBbls of oil, 3,328.5 MMcf of natural gas and 49.5 MBbl of natural gas liquids. Net sales for the year ended December 31, 2006, on an accrual basis, were 891.0 MBbls of oil, 5,056.7 MMcf of natural gas and 55.4 MBbls of natural gas liquids. The projected decrease in estimated production for the projected period is primarily the result of normal production decline. Whiting expects annual production attributable to the underlying properties to decline at an average year over year rate of approximately 11% between 2008 and 2017. Differing levels of production will result in different levels of distributions and cash returns.

Oil, Natural Gas and Natural Gas Liquid Prices. Hypothetical oil and natural gas prices assumed in the projected cash distribution table are based on the NYMEX futures prices for oil and natural gas on , 2008 and Bloomberg consensus price forecasts for oil and natural gas on , 2008. Published NYMEX benchmark prices for crude oil are based upon an assumed light, sweet crude oil of a particular gravity that is stored in Cushing, Oklahoma while published NYMEX benchmark prices for natural gas are based upon delivery at the Henry Hub in Louisiana. These prices differ from the average or actual price received for production attributable to the underlying properties. Differentials between published oil and natural gas prices and the prices actually received for the oil and natural gas production may vary significantly due to market conditions, transportation costs and other factors.

In the above tables, $8.23 per Bbl is deducted from the assumed sales price for crude oil in 2008 to reflect these differentials, which is the assumed differential used in the reserve report. This deduction is based on Whiting’s estimate of the average difference between the NYMEX published price of crude oil and the price to be received by Whiting for production attributable to the underlying properties during 2008. The average difference between the NYMEX published price of crude oil and the price received by Whiting for oil production attributable to the underlying properties during the nine months ended September 30, 2007 was $7.33 per Bbl. Pro forma average oil prices appearing in this prospectus have been adjusted for these differentials. Because there is no hedge in place or Bloomberg consensus price for natural gas liquids, Whiting used a hypothetical price equal to approximately 66% of the hypothetical price used in the projected cash distribution table for oil, which is consistent with the historical pricing realized by Whiting for natural gas liquids and is the methodology used in the reserve report.

In the cash distribution table, $0.60 per Mcf is deducted from the assumed sales price for natural gas in 2008 to reflect these differentials, which is the average difference between the NYMEX published price of natural gas and the price received by Whiting for natural gas production attributable to the underlying properties during the nine months ended September 30, 2007. This deduction is based on Whiting’s estimate of the average difference between the NYMEX published price of natural gas and the price to be received by Whiting for production attributable to the underlying properties during 2008.

The adjustments to published oil, natural gas and natural gas liquid prices applied in the above projected cash distribution estimate are based upon an analysis by Whiting of the historic price differentials for production from the underlying properties with consideration given to gravity, quality and transportation and marketing costs that may affect these differentials in 2008. There is no assurance that these assumed differentials will occur in 2008.

When oil, natural gas and natural gas liquid prices decline, the operators of the underlying properties may elect to reduce or completely suspend production. No adjustments have been made to estimated 2008 production to reflect potential reductions or suspensions of production.

Settlement of Hedge Contracts. The projected cash proceeds to the trust includes the impact of payments that would be made to settle the hedge contracts in 2008 based upon the hypothetical oil prices assumed in the

projected cash distribution table. In addition, the cash distribution table includes the impact of the amounts payable to Whiting from hedge contract counterparties upon settlements of the hedge contracts. Whiting has entered into costless collar arrangements with respect to $ Bbls of oil and $ Mcf of natural gas expected to be produced from the underlying properties during 2008 at a weighted average price per Bbl of $ and per Mcf of $ , respectively.

Costs. For 2008, Whiting estimates lease operating expenses to be $ million and production and property taxes to be $ million. For the nine months ended September 30, 2007, lease operating expenses were $17.0 million and production taxes were $4.4 million. For a description of production expenses, see “Computation of Net Proceeds — Net Profits Interest.” Whiting expects its costs in 2008 to be substantially the same as its expected costs in 2007.

Administrative Expense. Trust administrative expense for 2008 is assumed to be $900,000. See “The Trust.”

THE UNDERLYING PROPERTIES

The underlying properties consist of Whiting’s net interests in certain oil and natural gas producing properties as of the date of the conveyance of the net profits interest to the trust, which properties are located primarily in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions of the United States. The underlying properties include interests in approximately 3,000 producing oil and natural gas wells located in 173 fields on 195,616 gross acres in 14 states. Whiting has acquired interests in these properties through various acquisitions that have occurred during its 27 year existence. For the month ended September 30, 2007, the average daily net production from these properties was 4,508 BOE, which equates to 4,057 BOE to the net profits interest. Whiting operates approximately 60.6% of the underlying properties based on the pre-tax PV10% value.

Whiting’s interests in the oil and natural gas properties comprising the underlying properties require Whiting to bear its proportionate share, along with the other working interest owners, of the costs of development and operation of such properties. Many of the properties comprising the underlying properties that are operated by Whiting are burdened by non-working interests owned by third parties, consisting primarily of royalty interests retained by the owners of the land subject to the working interests. These landowners’ royalty interests typically entitle the landowner to receive at least 12.5% of the revenue derived from oil and natural gas production resulting from wells drilled on the landowner’s land, without any deduction for drilling costs or other costs related to production of oil and natural gas. A working interest percentage represents a working interest owner’s proportionate ownership interest in a property in relation to all other working interest owners in that property, whereas a net revenue interest percentage is a working interest owner’s percentage of production after reducing such percentage by the percentage of burdens on such production such as royalties and overriding royalties.

As of September 30, 2007, proved reserves attributable to the underlying properties, as estimated in the reserve report, were approximately 13.18 MMBOE with a pre-tax PV10% value of $243.5 million. The net profits interest entitles the trust to receive 90% of the net proceeds from the sale of production of 9.04 MMBOE of proved reserves. The 9.04 MMBOE represents the proved reserves attributable to the underlying properties that the reserve report projects to be produced by December 31, 2017. However, the exact rate of production cannot be predicted with certainty and such amount may be produced before or after that date. The reserves attributable to the underlying properties include all reserves expected to be economically produced during the life of the properties, whereas the trust is entitled to only receive 90% of the net proceeds from the sale of production of oil, natural gas and natural gas liquids attributable to the underlying properties during the term of the net profits interest.

In general, the producing wells to which the underlying properties relate have established production profiles. Based on the reserve report, annual production from the underlying properties is expected to decline at an average year over year rate of approximately 11% from 2008 through 2017. However, cash distributions to unitholders may decline at a faster rate than the rate of production due to fixed and semi-variable costs attributable to the underlying properties.

Historical Results of the Underlying Properties

The following table sets forth revenues, direct operating expenses and the excess of revenues over direct operating expenses relating to the underlying properties for the three years in the period ended December 31, 2006, and for the nine-month periods ended September 30, 2006 and 2007, derived from the underlying properties’ audited and unaudited statements of historical revenues and direct operating expenses included elsewhere in this prospectus. The unaudited statements were prepared on a basis consistent with the audited statements and, in the opinion of Whiting, include all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the revenues, direct operating expenses and the excess of revenues over direct operating expenses relating to the underlying properties for the periods presented. The historical financial information includes the results of acquisitions beginning on the following dates: Equity Oil Company, July 20, 2004; Permian Basin Properties, September 23, 2004; Institutional Partnership Interests, June 23, 2005; Celero Energy, LP, October 4, 2005; and Howard Energy, August 3, 2006.


							Nine months ended
	Year ended December 31,						September 30,
	2004		2005		2006		2006		2007
							(Unaudited)		(Unaudited)

Revenues:
Oil sales	$	30,539,666	$	43,498,823	$	53,232,066	$	41,058,591	$	41,148,501
Natural gas sales		23,460,243		36,135,271		31,397,455		24,193,531		20,736,595

Total revenues		53,999,909		79,634,094		84,629,521		65,252,122		61,885,096

Direct operating expenses:
Lease operating		10,854,433		16,180,693		21,912,702		15,687,225		16,952,622
Production tax		3,954,703		5,602,452		6,006,308		4,621,121		4,365,517

Total direct operating expenses		14,809,136		21,783,145		27,919,010		20,308,346		21,318,139

Excess of revenues over direct operating expenses	$	39,190,773	$	57,850,949	$	56,710,511	$	44,943,776	$	40,566,957


							Nine months ended
	Year ended December 31,						September 30,
	2004		2005		2006		2006		2007

Operating data:
Net production:
Oil (MBbls)		827		893		946		704		717
Natural gas (MMcf)		4,268		5,082		5,057		3,838		3,328
Total production (MBOE)		1,538		1,740		1,789		1,344		1,271
Oil (per Bbl)	$	36.95	$	48.72	$	56.24	$	58.32	$	57.42
Natural gas (per Mcf)	$	5.50	$	7.11	$	6.21	$	6.30	$	6.23
Drilling and development capital expenditures (in thousands)(1):	$	6,396	$	6,453	$	10,036	$	6,908	$	5,280


(1)		Whiting cannot provide any assurance that future capital expenditures will be consistent with historical levels.

Discussion and Analysis of Historical Results of the Underlying Properties

Comparison of Results of the Underlying Properties for the Nine Months Ended September 30, 2007 and 2006

Revenues. Oil and natural gas sales revenue decreased $3.4 million to $61.9 million in the first nine months of 2007 compared to the first nine months of 2006. Sales are a function of volumes sold and average sales prices. Oil sales volumes increased 2% primarily due to the acquisition of Howard Energy in August of 2006, while gas sales volumes decreased 13% between periods primarily due to normal field production decline. Average price for oil decreased 2% and its average price for natural gas decreased 1% between periods.

Lease Operating Expenses. Lease operating expenses increased $1.3 million to $17.0 million in the first nine months of 2007 compared to the first nine months of 2006 primarily due to the acquisition of Howard Energy in August of 2006. Lease operating expense as a percentage of oil and gas sales increased from 24% during the first nine months of 2006 to 27% during the first nine months of 2007. Lease operating expenses per BOE increased from $11.67 during the first nine months of 2006 to $13.33 during the first nine months of 2007. The increase of 14% on a BOE basis was primarily caused by inflation in the cost of oil field goods and services. The cost of oil field goods and services increased due to a higher demand in the industry.

Production Taxes. Production taxes are generally calculated as a percentage of oil and gas sales revenue. All credits and exemptions allowed in the various taxing jurisdictions are fully utilized. Production taxes for the first nine months of 2007 and 2006 were 7.1% of oil and gas sales.

Excess of Revenues Over Direct Operating Expenses. Excess of revenues over direct operating expenses decreased from $44.9 million during the first nine months of 2006 to $40.6 million during the first nine months of 2007. The primary reasons for this decrease included a 5% decrease in equivalent volumes sold, a 2% decrease in oil prices and a 1% decrease in gas prices between periods, and higher lease operating expense. The decreased production and pricing and increased lease operating expenses were partially offset by lower production taxes in the first nine months of 2007.

Comparison of Results of the Underlying Properties for the Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

Revenues. Oil and natural gas sales revenue increased $5.0 million to $84.6 million in 2006 compared to 2005. Sales are a function of volumes sold and average sales prices. Oil sales volumes increased 6% primarily due to new property acquisitions during 2005 and 2006 and gas sales volumes decreased slightly between periods. Average price for oil increased 15% and its average price for natural gas decreased 13% between periods.

Lease Operating Expenses. Lease operating expense increased $5.7 million to $21.9 million in 2006 compared to 2005. The increase resulted primarily from costs associated with new property acquisitions during 2005 and 2006 and successful drilling activities over the past year. Lease operating expense as a percentage of oil and gas sales increased from 20% during 2005 to 26% during 2006, and lease operating expenses per BOE increased from $9.30 during 2005 to $12.25 during 2006. The increase of 32% on a BOE basis was primarily caused by inflation in the cost of oil field goods and services, a high level of workover activity and higher energy costs. Oil field goods and services increased due to a higher demand in the industry. Workovers amounted to $1.7 million in 2006, as compared to $0.7 million of workover activity during 2005.

Production Taxes. Production taxes are generally calculated as a percentage of oil and gas sales revenue. All credits and exemptions allowed in the various taxing jurisdictions are fully utilized. Production taxes for 2006 and 2005 were 7.1% and 7.0%, respectively, of oil and gas sales.

Excess of Revenues Over Direct Operating Expenses. Excess of revenues over direct operating expenses decreased from $57.9 million in 2005 to $56.7 million for 2006. The primary reasons for this decrease included higher lease operating expenses and production taxes in 2006 resulting from continued growth, partially offset by a 3% increase in total production.

Comparison of Results of the Underlying Properties for the Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

Revenues. Oil and natural gas sales revenue increased $25.6 million to $79.6 million in 2005 as compared to 2004. Sales are a function of volumes sold and average sales prices. Oil sales volumes increased 8% primarily due to recent acquisitions, and its gas sales volumes decreased 19% between periods primarily due to normal field production decline. Average price for crude oil increased 32% between periods and the average price for natural gas sales increased 29%.

Lease Operating Expenses. Lease operating expense increased $5.3 million to $16.2 million in 2005 compared to 2004. The increase resulted primarily from new property acquisitions during 2004 and 2005. Lease operating expenses per BOE increased from $7.06 during 2004 to $9.30 during 2005. The increase of 32% on a BOE basis was mainly caused by higher costs for electric power and increases in the cost of oil field goods and services due to higher demand in the industry.

Production Taxes. Production taxes are generally calculated as a percentage of oil and gas sales revenue. All credits and exemptions allowed by the various taxing jurisdictions are fully utilized. Production taxes for 2005 and 2004 were 7.0% and 7.3%, respectively, of oil and gas sales.

Excess of Revenues Over Direct Operating Expenses. Excess of revenues over direct operating expenses increased from $39.2 million during 2004 to $57.9 million during 2005. The primary reasons for this increase included 30% higher realized price between periods and a 13% increase in equivalent volumes sold, which were partially offset by higher lease operating expenses and production taxes in 2005 resulting from continued growth.

Hedge Contracts

The revenues derived from the underlying properties depend substantially on prevailing crude oil, natural gas and natural gas liquid prices. As a result, commodity prices also affect the amount of cash flow available for distribution to the trust unitholders. Lower prices may also reduce the amount of oil, natural gas and natural gas liquids that Whiting can economically produce. Whiting sells the oil, natural gas and natural gas liquid production from the underlying properties under floating market price contracts each month. Whiting has entered into the hedge contracts to reduce the exposure of the revenues from oil and natural gas production from the underlying properties from January 1, 2008 through December 31, 2012 to fluctuations in crude oil and natural gas prices and to achieve more predictable cash flow. However, these contracts limit the amount of cash available for distribution if prices increase. The hedge contracts consist of costless collar arrangements that will be placed with major trading counterparties who Whiting believes represent minimal credit risks. Whiting cannot provide assurance, however, that these trading counterparties will not become credit risks in the future.

The costless collar arrangements will settle based on the average of the settlement price for each commodity business day in the contract period. In a collar arrangement, the counterparty is required to make a payment to Whiting for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. Whiting is required to make a payment to the counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed

ceiling price. From January 1, 2008 through December 31, 2012, Whiting’s crude oil and natural gas price risk management positions in collar arrangements are as follows:

Oil Collars

Natural Gas Collars

Weight Average

Weighted Average

Volumes

Price (per Bbl)

Volumes

Price (Per Mcf)

(Bbls)

Floor

Ceiling

(Mcf)

Floor

Ceiling

Year Ending December 31, 2008

Year Ending December 31, 2009

Year Ending December 31, 2010

Year Ending December 31, 2011

Year Ending December 31, 2012

The amounts received by Whiting from hedge contract counterparties upon settlements of the hedge contracts will reduce the operating expenses related to the underlying properties in calculating the net proceeds. However, if the hedge payments received by Whiting under the hedge contracts and other non-production revenue exceed operating expenses during a quarterly period, the ability to use such excess amounts to offset operating expenses will be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period where the hedge payments and the other non-production revenue are less than such expenses. In addition, the aggregate amounts paid by Whiting on settlement of the hedge contracts will reduce the amount of net proceeds paid to the trust. See “Computation of Net Proceeds — Net Profits Interest.”

Producing Acreage and Well Counts

For the following data, “gross” refers to the total wells or acres in the oil and natural gas properties in which Whiting owns a working interest and “net” refers to gross wells or acres multiplied by the percentage working interest owned by Whiting. Although many of Whiting’s wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas production.

The underlying properties are interests in developed properties located in oil and natural gas producing regions outlined in the chart below. The following is a summary of the approximate acreage of these properties at September 30, 2007. Undeveloped acreage is not significant.


	Gross		Net
	(acres)

Rocky Mountains		85,844		38,334
Mid-Continent		57,943		26,708
Permian Basin		23,974		8,090
Gulf Coast		27,855		5,133

Total		195,616		78,265

The following is a summary of the producing wells on the underlying properties as of September 30, 2007:


	Operated Wells				Non-Operated Wells				Total
	Gross		Net		Gross		Net		Gross		Net

Oil		284		179.3		2,071		82.0		2,355		261.3
Natural gas		89		63.8		564		56.5		653		120.3

Total		373		243.1		2,635		138.5		3,008		381.6

The following is a summary of the number of developmental wells drilled by Whiting on the underlying properties during the last three years. Whiting did not drill any exploratory wells during the periods presented.


	Year Ended December 31,
	2004				2005				2006
	Gross		Net		Gross		Net		Gross		Net

Completed
Oil wells		2		0.6		2		0.3		18		2.1
Natural gas wells		5		1.1		6		2.0		12		1.8
Non-productive		0		0.0		0		0.0		0		0.0

Total		7		1.7		8		2.3		30		3.9

The following table shows the average sales prices per Bbl of oil and Mcf of natural gas produced and the production costs and production and property taxes per BOE for the underlying properties. Sales volumes for natural gas liquids during the periods presented were not significant. There were no hedges or other derivative activity attributable to the underlying properties during such periods.


	Year ended December 31,
	2004		2005		2006

Average sales prices:
Oil (MBbls)	$	36.95	$	48.72	$	56.24
Natural gas (MMcf)	$	5.50	$	7.11	$	6.21
Lease operating expense per BOE	$	7.06	$	9.30	$	12.25
Production tax per BOE	$	2.57	$	3.22	$	3.36

Major Producing Areas

The following table summarizes the estimated proved reserves by region and by the major fields within each region attributable to the net profits interest according to the reserve report, the corresponding pre-tax PV10% value as of September 30, 2007 and the average daily net production attributable to the net profits interest for the month of September 2007.


			Proved Reserves(1)														September
												Pre-Tax		% of Total			2007 Average
					Natural				% of			PV10%		Pre-Tax			Daily Net
			Oil		Gas		Total		Total			Value(2)(3)		PV10%			Production
Region/Field	State		(Mbbl)		(MMcf)		(MBOE)(2)		Reserves			(In millions)		Value			(BOE/d)

Rocky Mountains (65 Fields)
Bainville		MT		164		120		184		2.3	%	$	6.4		3.2	%		88
Palomino		MT		158		0		158		1.9			5.8		2.9			53
Sage Creek		WY		223		0		223		2.7			6.2		3.1			83
Whiskey Joe		ND		134		66		145		1.8			5.5		2.8			63
Bell		ND		145		0		145		1.8			5.2		2.6			50
Fryberg		ND		159		14		161		2.0			4.1		2.1			109
Davis Creek		ND		149		0		149		1.8			5.1		2.6			72
Kiehl		WY		130		0		130		1.6			3.9		2.0			49
Ignacio Blanco		CO		0		615		103		1.3			1.4		0.7			89
Other				1,309		1,752		1,601		19.6			40.3		20.3			629

Rocky Mountains Total				2,571		2,567		2,999		36.8	%	$	83.9		42.3	%		1,285
Mid-Continent (54 Fields)
Magnolia Smackover Pool Unit		AR		866		1,288		1,081		13.2	%	$	24.8		12.5	%		406
Case		MI		172		127		193		2.4			7.2		3.6			111
Putnam		OK		78		1,154		270		3.3			6.2		3.1			244


			Proved Reserves(1)														September
												Pre-Tax		% of Total			2007 Average
					Natural				% of			PV10%		Pre-Tax			Daily Net
			Oil		Gas		Total		Total			Value(2)(3)		PV10%			Production
Region/Field	State		(Mbbl)		(MMcf)		(MBOE)(2)		Reserves			(In millions)		Value			(BOE/d)

Mocane-Laverne Gas Area		OK		10		1,694		293		3.6			4.6		2.3			112
Sho-Vel-Tum		OK		68		186		99		1.2			3.2		1.6			35
Nobscot Northwest		OK		36		984		200		2.5			2.6		1.3			97
Other				329		4,867		1,140		14.0			22.1		11.2			618

Mid-Continent Total				1,559		10,300		3,276		40.2	%	$	70.7		35.6	%		1,623
Permian Basin (28 Fields)
Iatan East Howard		TX		249		65		259		3.2	%	$	6.5		3.3	%		94
Fullerton		TX		172		54		181		2.2			5.0		2.5			83
Patricia		TX		121		47		129		1.6			5.0		2.5			49
Other				295		1,826		600		7.4			12.1		6.1			376

Permian Basin Total				837		1,992		1,169		14.4	%	$	28.6		14.4	%		602
Gulf Coast (26 Fields)
Mestena Grande		TX		11		632		116		1.4	%	$	2.6		1.3	%		61
Other				179		2,411		581		7.2			12.7		6.4			486

Gulf Coast Total				190		3,043		697		8.6	%	$	15.3		7.7	%		547
Total				5,157		17,902		8,141		100.0	%	$	198.5		100.0	%		4,057


(1)		The net profits interest entitles the trust to receive 90% of the net proceeds from the sale of production of 9.04 MMBOE from the underlying properties taken as a whole. The allocation and make up of such reserves among regions is from the reserve report and may not reflect the actual location and make up from which reserves will be produced under the net profits interest.

(2)		The total proved reserves attributable to the underlying properties, as estimated in the reserve report, were 13.18 MMBOE with a pre-tax PV10% value of $243.5 million, although the net profits interest will terminate when 9.04 MMBOE have been produced. The amounts in the table reflect the trust’s 90% net profits interest in such reserves. Proved reserves reflected in the table above for the net profits interest are based on NYMEX oil and natural gas prices as of September 30, 2007 of $81.66 per Bbl of oil and $6.15 per Mcf of natural gas less field transportation, quality and basis differentials of $8.20 per Bbl of oil and $0.25 per Mcf of natural gas, resulting in field adjusted prices of $73.46 per Bbl of oil and $5.90 per Mcf of natural gas.


(3)		Pre-tax PV10% value may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Pre-tax PV10% value is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. However, as of September 30, 2007, no provision for federal or state income taxes has been provided because taxable income is passed through to the unitholders of the trust. Therefore, the standardized measure of discounted future net cash flows attributable to the net profits interest is equal to the pre-tax PV10% value. The pre-tax PV10% value and the standardized measure of discounted future net cash flows do not purport to present the fair value of the oil and natural gas reserves attributable to the net profits interest.

The underlying properties are located in several major onshore producing basins in the continental United States. Whiting believes this broad distribution provides a buffer against regional trends that may negatively impact production or prices. Based on the pre-tax PV10% value, approximately 60.6% of these properties are operated by Whiting, and, as of September 30, 2007, these properties’ reserves were 63.3% oil and natural gas liquids and 36.7% natural gas according to the reserve report. These properties are located in mature fields

and have established production profiles. However production and distributions to the trust will decline over time.

No. of Wells

Gross/

Average

Average Net

Operated/

Net

Working

Revenue

Field

Non-Operated

Operator

State

County

Productive Zones

Acres

Interest

Bainville

3/16

Whiting and Others

Roosevelt

Mission Canyon,
Ratcliff, Nisku,
Winnipegosis

5,150/1,010

15.7

12.9

Palomino

5/0

Whiting

Roosevelt

Nisku

880/880

54.4

45.7

Sage Creek

22/0

Whiting

Park

Madison, Tensleep

1,363/488

46.1

39.5

Whiskey Joe

2/4

Whiting and Others

Billings

Madison

7,503/3,071

32.5

26.6

Bell

1/2

Whiting and Others

Stark

Tyler

324/125

60.4

50.6

Fryberg

0/58

Hess Corporation
and Others

Billings

Tyler

6,225/3,427

36.8

30.8

Davis Creek

8/5

Whiting and Others

Billings

Fryberg

9,213/4,316

37.6

31.5

Kiehl

5/1

Whiting and Others

Crook

Minnelusa

359/359

29.7

22.7

Ignacio Blanco

0/8

BP Exploration &
Production Inc.

LaPlatta

Fruitland Coal

680/130

19.4

14.8

Mid-Continent Region. The underlying properties in the Mid-Continent region are located in Arkansas, Kansas, Michigan and Oklahoma. These properties include 54 fields of which Whiting operates wells in 30 of these fields. Average daily net production attributable to the net profits interest from these properties was 1,623 BOE/d for the month of September 2007 from 455 wells that will be burdened by the net profits interest. The following table summarizes Whiting’s interests in the major fields in this region.

No. of Wells

Gross/

Average

Average Net

Operated/

Net

Working

Revenue

Field

Non-Operated

Operator

State

County

Productive Zones

Acres

Interest

Magnolia Smackover
Pool Unit

60/0

Whiting

Columbia

Smackover

4,503/2,592

76.0

73.9

Case

5/1

Whiting

Pesque Isle

Niagaran

986/946

73.3

61.3

Putnam

11/7

Whiting

Dewey

Oswego,

5,465/2,875

43.8

35.0

and Others

Tonkawa,

Morrow,
Red Fork,
Cottage Grove
and Atoka

Mocane-Laverne Gas Area

17/19

Whiting

Beaver,

Morrow

14,837/8,034

54.1

38.7

and Others

Harper, Ellis

Sho-Vel-Tum

0/99

Keith Walker Oil

Carter

Hunton,

700/195

20.4

18.8

and Gas

Penn

Nobscot Northwest

85/0

Whiting

Dewey,

Oswego

5,467/2,354

53.4

45.3

Custer

these properties was 602 BOE/d for the month of September 2007 from approximately 1,612 wells that will be burdened by the net profits interest. The following table summarizes Whiting’s interests in the major fields in this region.

No. of Wells

Gross/

Average

Average Net

Operated/

Net

Working

Revenue

Field

Non-Operated

Operator

State

County

Productive Zones

Acres

Interest

Iatan East Howard

0/414

CrownQuest
Operating, LLC

Howard,
Mitchell

San Andres,
San Angelo
(Glorieta),
and Clear Fork

3,840/322

8.4

7.0

Fullerton

10/880

Exxon Mobil
Corporation and
Whiting

Andrews

Clear Fork

1,840/1,563

60.1

45.0

Patricia

5/1

Whiting
and Others

Dawson

Fusselman and
Sprayberry

1,417/ 1,337

66.7

54.3

Gulf Coast Region. The underlying properties in the Gulf Coast region are located in Texas, Louisiana, Mississippi and Alabama. These properties include 26 onshore fields of which Whiting operates wells in two of these fields. Average daily net production attributable to the net profits interest from these properties was predominately natural gas and was 547 BOE/d for the month of September 2007 from approximately 264 wells that will be burdened by the net profits interest. The following table summarizes Whiting’s interest in the major field in this region.

No. of Wells

Gross/

Average

Average Net

Operated/

Net

Working

Revenue

Field

Non-Operated

Operator

State

County

Productive Zones

Acres

Interest

Mestena Grande

0/33

Cabot Oil &
Gas Corporation

Jim Hogg

Queen City

10,691/1,334

12.9

9.8

Reserves

Cawley, Gillespie & Associates, Inc. estimated oil (including natural gas liquids) and natural reserves attributable to the underlying properties as of September 30, 2007. Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the original estimates.

Cawley, Gillespie & Associates, Inc. calculated reserve quantities and revenues attributable to the net profits interest based on projections of reserves and revenues attributable to the underlying properties less reserve quantities of a sufficient value to pay 90% of the future estimated costs, before trust administrative expenses, that are deducted in calculating net proceeds. Proved reserve quantities attributable to the net profits interest are calculated by multiplying the gross reserves for the underlying properties by the net profits interest assigned to the trust in the underlying properties. The net revenues attributable to the trust’s reserves are net of the share of applicable production expenses, taxes and post-production costs that are used to calculate the net profits interest. The reserves and net revenues attributable to the net profits interest include only the reserves attributable to the underlying properties that are expected to be produced within the term of the net profits interest calculated as described above.

The discounted estimated future net revenues presented below were prepared using assumptions required by the SEC. Except to the extent otherwise described below, these assumptions include the use of NYMEX oil and natural gas prices as of September 30, 2007 of $81.66 per Bbl of oil and $6.15 per Mcf of natural gas less field transportation, quality and basis differentials of $8.20 per Bbl of oil and $0.25 per Mcf of natural gas, resulting in field adjusted prices of $73.46 per Bbl of oil and $5.90 per Mcf of natural gas, as well as costs for estimated future development and production expenditures to produce the proved reserves as of September 30, 2007. Because oil and natural gas prices are influenced by many factors, use of prices as of September 30, 2007, as required by the SEC, may not be the most accurate basis for estimating future revenues of reserve data. Future net cash flows are discounted at an annual rate of 10%. There is no provision for federal income taxes with respect to the future net cash flows attributable to the net profits interest because future net

revenues are not subject to taxation at the trust level. See “Federal Income Tax Consequences” for more information.

Proved Reserves of Underlying Properties and the Net Profits Interest. The following table sets forth, as of September 30, 2007, certain estimated proved reserves, estimated future net revenues and the discounted present value thereof attributable to the underlying properties and the net profits interest, in each case derived from the reserve report. A summary of the reserve report is included as Appendix A to this prospectus.


			Underlying
			Properties		Net Profits
	Underlying		(attributable to the		Interest with
	Properties(1)(2)		net profits interest)(3)		cost reductions(4)
	(in thousands, except Bbl, Mcf and BOE amounts)

Proved Reserves:
Oil and natural gas liquids(MBbls)		8,663		5,157		3,016
Natural gas (MMcf)		27,082		17,902		10,569
Oil equivalents (MBOE)		13,176		8,141		4,778
Future net revenues	$	415,055	$	279,074	$	279,074
Discounted estimated future net revenues(5)	$	243,535	$	198,481	$	198,481
Standardized measure(6)	$	243,535	$	198,481	$	198,481


(1)		The net profits interest entitles the trust to receive 90% of the net proceeds from the sale of production of 9.04 MMBOE from the underlying properties.

(2)		Reserve volumes and estimated future net revenues for underlying properties reflect volumes and revenues attributable to the underlying properties during the term of the net profits interest.

(3)		Reflects 90% of the estimated proved reserves attributable to the underlying properties expected to be produced within the term of the net profits interest based on the reserve report. Estimated future net revenues from proved reserves takes into account future estimated costs that are deducted in calculating net proceeds.

(4)		Proved reserves for the net profits interest are calculated as (x) 90% of the estimated proved reserves of the underlying properties less (y) reserve quantities of a sufficient value to pay 90% of the future estimated costs that are deducted in calculating net proceeds. Accordingly, proved reserves for the net profits interest reflect quantities expected to be produced during the term of the net profits interest that are calculated after reductions for future costs and expenses based on price and cost assumptions used in the reserve estimates. Estimated future net revenues from proved reserves takes into account future estimated costs that are deducted in calculating net proceeds.

(5)		No provision for federal or state income taxes has been provided because taxable income is passed through to the trust unitholders. The present values of future net revenues for the underlying properties and the net profits interest were determined using a discount rate of 10% per annum.

(6)		No provision for federal or state income taxes has been provided because taxable income is passed through to the unitholders of the trust. Therefore, the standardized measure of the underlying properties and the underlying properties attributable to the net profits interest equal their corresponding pre-tax PV10% values, which totaled $243.5 million and $198.5 million, respectively, as of September 30, 2007.

Information concerning historical changes in proved reserves attributable to the underlying properties, and the calculation of the standardized measure of discounted future net revenues related thereto, is contained in the unaudited supplemental information contained elsewhere in this prospectus. Whiting has not filed reserve estimates covering the underlying properties with any other federal authority or agency.

The following table summarizes the changes in estimated proved reserves of the underlying properties for the periods indicated.


	Oil (Mbbl)			Nat. Gas (MMcf)			(MBOE)
Balance at January 1, 2004		7,295			35,579			13,225
Revisions, extensions, discoveries and additions		2,587			12,495			4,670
Production		(827	)		(4,268	)		(1,538	)

Balance at December 31, 2004		9,055			43,806			16,357
Revisions, extensions, discoveries and additions		1,887			281			1,934
Production		(893	)		(5,082	)		(1,740	)

Balance at December 31, 2005		10,049			39,005			16,551
Revisions, extensions, discoveries and additions		(248	)		(2,058	)		(591	)
Production		(946	)		(5,057	)		(1,789	)

Balance at December 31, 2006		8,855			31,890			14,171
Revisions, extensions, discoveries and additions		525			(1,480	)		276
Production		(717	)		(3,328	)		(1,271	)

Balance at September 30, 2007		8,663			27,082			13,176



Proved developed reserves:
Balance at December 31, 2004		9,037			43,795			16,336

Balance at December 31, 2005		10,027			38,989			16,525

Balance at December 31, 2006		8,849			31,546			14,107

Balance at September 30, 2007		8,663			27,082			13,176

Abandonment of Underlying Properties

Whiting will have the right to abandon its interest in any well or property comprising a portion of the underlying properties if, in its opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities. To reduce or eliminate the potential conflict of interest between Whiting and the trust in determining whether a well is capable of producing in commercially paying quantities, Whiting has agreed to operate the underlying properties as a reasonably prudent operator in the same manner that it would operate if these properties were not burdened by the net profits interest and Whiting has agreed to use commercially reasonable efforts to cause the other operators to operate these properties in the same manner. For the years ended December 31, 2004, 2005 and 2006, Whiting plugged and abandoned 3, 6 and 0 wells, respectively, with respect to the underlying properties based on its determination that such wells were no longer economic to operate.

Marketing and Post-Production Services

Pursuant to the terms of the conveyance creating the net profits interest, Whiting will have the responsibility to market, or cause to be marketed, the oil, natural gas and natural gas liquid production attributable to the underlying properties. The terms of the conveyance creating the net profits interest do not permit Whiting to charge any marketing fee other than fees for marketing paid to non-affiliates when determining the net proceeds upon which the net profits interest will be calculated. As a result, the net proceeds to the trust from the sales of oil, natural gas and natural gas liquid production from the underlying properties will be determined based on the same price that Whiting receives for oil, natural gas and natural gas liquid production attributable to Whiting’s remaining interest in the underlying properties.

Whiting principally sells its 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. Whiting’s marketing of oil and natural gas can be affected by factors beyond its control, the effects of which cannot be accurately predicted.

Title to Properties

The underlying properties are subject to certain burdens that are described in more detail below. To the extent that these burdens and obligations affect Whiting’s rights to production and the value of production from the underlying properties, they have been taken into account in calculating the trust’s interests and in estimating the size and the value of the reserves attributable to the underlying properties.

Whiting’s interests in the oil and natural gas properties comprising the underlying properties are typically subject, in one degree or another, to one or more of the following:


	•	royalties, overriding royalties and other burdens on production, express and implied, under oil and natural gas leases;

	•	overriding royalties, production payments and similar interests and other burdens on production created by Whiting or its predecessors in title;

	•	a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect these properties or Whiting’s title thereto;

	•	liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;

	•	pooling, unitization and communitization agreements, declarations and orders;

	•	easements, restrictions, rights-of-way and other matters that commonly affect property;

	•	conventional rights of reassignment that obligate Whiting to reassign all or part of a property to a third party if Whiting intends to release or abandon such property; and

	•	rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the underlying properties and the net profits interest therein.

Whiting believes that the burdens and obligations affecting the oil and natural gas properties comprising the underlying properties are conventional in the industry for similar properties. Whiting also believes that the existing burdens and obligations do not, in the aggregate, materially interfere with the use of these properties and will not materially adversely affect the value of the net profits interest.

Whiting acquired the underlying properties in various transactions that have occurred during its 27 year existence. At the time of its acquisitions of the underlying properties, Whiting undertook a title examination of these properties.

Oil and natural gas leases are generally considered real property interests under the laws of the jurisdictions where the underlying properties are located. Net profits interests are non-operating, non-possessory interests carved out of the oil and natural gas leasehold estate, but some jurisdictions have not directly determined whether a net profits interest is a real or a personal property interest. Whiting believes that it is possible that the net profits interest may not be treated as a real property interest under the laws of certain of the jurisdictions where the underlying properties are located. Whiting intends, however, to record the conveyance of the net profits interest in the relevant real property records of all applicable jurisdictions. Whiting believes that, if, during the term of the trust, Whiting becomes involved as a debtor in a bankruptcy proceeding, the net profits interest relating to the underlying properties in most, if not all, of the jurisdictions should be treated as a fully conveyed property interest. In such a proceeding, however, a determination could be made that the conveyance constitutes an executory contract and the net profits interest is not a fully conveyed property interest under the laws of the applicable jurisdiction, and if such contract were not to be

assumed in a bankruptcy proceeding involving Whiting, the trust would be treated as an unsecured creditor of Whiting with respect to such net profits interest in the pending bankruptcy proceeding. Although no assurance can be given, Whiting believes that the conveyance of the net profits interest relating to the underlying properties in most, if not all, of the jurisdictions of which these properties are located should not be subject to rejection in a bankruptcy proceeding as an executory contract.

Competition and Markets

The oil and natural gas industry is highly competitive. Whiting competes with major oil and natural gas companies and independent oil and natural gas companies for oil and natural gas, equipment, personnel and markets for the sale of oil and natural gas. Many of these competitors are financially stronger than Whiting, but even financially troubled competitors can affect the market because of their need to sell oil and natural gas at any price to attempt to maintain cashflow. The trust will be subject to the same competitive conditions as Whiting and other companies in the oil and natural gas industry.

Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Future price fluctuations for oil, natural gas and natural gas liquids will directly impact trust distributions, estimates of reserves attributable to the trust’s interests and estimated and actual future net revenues to the trust. In view of the many uncertainties that affect the supply and demand for oil and natural gas, neither the trust nor Whiting can make reliable predictions of future oil and natural gas supply and demand, future product prices or the effect of future product prices on the trust.

Environmental Matters and Regulation

General. The operations of the underlying properties are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:


	•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production activities;

	•	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

	•	require investigatory and remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and

	•	enjoin some or all of the operations of underlying properties deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental statues impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, these laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on the operating costs of the underlying properties.

The following is a summary of the existing laws, rules and regulations to which the operations of the underlying properties are subject that are material to the operation of the underlying properties.

Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in the costs to manage and dispose of wastes, which could have a material adverse effect on the cash distributions to the trust unitholders.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, and comparable state laws impose strict joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to 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. Whiting has not been notified that it has been named as a potentially responsible party to any Superfund sites. In addition, 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.

The underlying properties may have been used for oil and natural gas exploration and production for many years. Although Whiting believes that it has utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, the underlying properties may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under Whiting’s control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, Whiting could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges. The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into state waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Global Warming and Climate Control. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of

greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas where the underlying properties operate could adversely affect demand for oil and gas products that, in turn, could limit cash distributions to the trust unitholders.

Air Emissions. The Federal Clean Air Act, and comparable state laws, regulate emissions of various air pollutants from various industrial sources through air emissions permitting programs and also impose other monitoring and reporting requirements. Operators of the underlying properties may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

OSHA and Other Laws and Regulation. Whiting is subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that Whiting organize and/or disclose information about hazardous materials used or produced in its operations. Whiting believes that it is in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

The federal Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security (“DHS”) to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to the act and the DHS is currently adopting an Appendix A to the interim rules that establish the chemicals of concern and their respective threshold quantities that will trigger compliance with the interim rules. Whiting has not yet determined the costs to comply with the interim rules but such costs could be substantial.

Consideration of Environmental Issues in Connection with Governmental Approvals. Whiting’s operations frequently require licenses, permits and/or other governmental approvals. Several federal statutes, including the Outer Continental Shelf Lands Act and the National Environmental Policy 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.

Whiting believes that it is in substantial compliance with all existing environmental laws and regulations applicable to the current operations of the underlying properties and that its continued compliance with existing requirements will not have a material adverse effect on the cash distributions to the trust unitholders. For instance, Whiting did not incur any material capital expenditures for remediation or pollution control activities for the period ended September 30, 2007 with respect to these properties. Additionally, as of the date of this prospectus, it is not aware of any environmental issues or claims that will require material capital expenditures during the remainder of 2007 with respect to these properties. However, there is no assurance that the passage of more stringent laws or implementing regulations in the future will not have an negative impact on the operations of these properties and the cash distributions to the trust unitholders.

COMPUTATION OF NET PROCEEDS

The provisions of the conveyance governing the computation of the net proceeds are detailed and extensive. The following information summarizes the material information contained in the conveyance related to the computation of the net proceeds. This summary may not contain all information that is important to you. For more detailed provisions concerning the net profits interest, you should read the conveyance. A copy of the conveyance has been filed as an exhibit to the registration statement of which this prospectus is a part. See “Where You Can Find More Information.”

Net Profits Interest

Whiting Petroleum Corporation’s wholly-owned subsidiaries, Whiting Oil and Gas Corporation and Equity Oil Company, will convey a term net profits interest to the trust by means of a conveyance instrument that will be recorded in the appropriate real property records in each county where the underlying properties are located. The net profits interest will burden the existing net interests owned by Whiting in the underlying properties. In the underlying properties in which Whiting is designated as the operator, Whiting has an average working interest of approximately 68.3% and an average net revenue interest of approximately 55.9%. For the underlying properties where Whiting is not the operator, Whiting has an average working interest of approximately 16.9% and an average net revenue interest of approximately 14.0%

The conveyance creating the net profits interest provides that the trust will be entitled to receive an amount of cash for each quarter equal to 90% of the net proceeds (calculated as described below) from the sale of oil, natural gas and natural gas liquid production attributable to the underlying properties.

The amounts paid to the trust for the net profits interest are based on the definitions of “gross proceeds” and “net proceeds” contained in the conveyance and described below. Under the conveyance, net proceeds are computed quarterly, and 90% of the aggregate net proceeds attributable to a computation period will be paid to the trust no later than 60 days following the end of the computation period (or the next succeeding business day). Whiting will not pay to the trust any interest on the net proceeds held by Whiting prior to payment to the trust. The trustee will make distributions to trust unitholders quarterly. See “Description of the Trust Units — Distributions and Income Computations.”

“Gross proceeds” means the aggregate amount received by Whiting from sales of oil, natural gas and natural gas liquids produced from the underlying properties (other than amounts received for certain future non-consent operations). Gross proceeds does not include any amount for oil, natural gas or natural gas liquids lost in production or marketing or used by Whiting in drilling, production and plant operations. Gross proceeds includes “take-or-pay” or “ratable take” payments for future production in the event that they are not subject to repayment due to insufficient subsequent production or purchases.

“Net proceeds” means gross proceeds less Whiting’s share of the following:


	•	all payments to mineral or landowners, such as royalties or other burdens against production, delay rentals, shut-in oil and natural gas payments, minimum royalty or other payments for drilling or deferring drilling;

	•	any taxes paid by the owner of an underlying property to the extent not deducted in calculating gross proceeds, including estimated and accrued general property (ad valorem), production, severance, sales, gathering, excise and other taxes;

	•	the aggregate amounts paid by Whiting upon settlement of the hedge contracts on a quarterly basis, as specified in the hedge contracts;

	•	any extraordinary taxes or windfall profits taxes that may be assessed in the future that are based on profits realized or prices received for production from the underlying properties;

	•	costs paid by an owner of an oil and natural gas property comprising the underlying properties under any joint operating agreement;


	•	costs and expenses, costs and liabilities of workovers, operating and producing oil, natural gas and natural gas liquids, including allocated expenses such as labor, vehicle and travel costs and materials and any plugging and abandonment liabilities other than costs and expenses for certain future non-consent operations;

	•	costs or charges associated with gathering, treating and processing oil, natural gas and natural gas liquids;

	•	a producing overhead charge in accordance with existing operating agreements;

	•	to the extent Whiting is the operator of an underlying property and there is no operating agreement covering such underlying property, the overhead charges allocated by Whiting to such underlying property calculated in the same manner Whiting allocates overhead to other similarly owned property;

	•	costs for recording the conveyance and costs estimated to record the termination and/or release of the conveyance;

	•	costs paid to counterparties under the hedge contracts or to the persons that provide credit to maintain any hedge contracts, excluding any hedge settlement amounts;

	•	amounts previously included in gross proceeds but subsequently paid as a refund, interest or penalty; and

	•	costs and expenses for renewals or extensions of leases.

All of the hedge payments received by Whiting from hedge contract counterparties upon settlements of hedge contracts and certain other non-production revenues, including salvage value for equipment related to plugged and abandoned wells, as detailed in the conveyance will offset the operating expenses outlined above in calculating the net proceeds. If the hedge payments received by Whiting and certain other non-production revenues exceed the operating expenses during a quarterly period, the ability to use such excess amounts to offset operating expenses will be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period when such amounts are less than such expenses. If any excess amounts have not been used to offset costs at the time when 9.04 MMBOE have been produced from the underlying properties and sold, which is the time when the net profits interest will terminate, then unitholders will not be entitled to receive the benefit of such excess amounts.

Capital expenditures for the testing, drilling, completion, equipping or plugging back of any well that is a part of the underlying properties will not be deducted from gross proceeds.

As is customary in the oil and natural gas industry, Whiting will deduct from the gross proceeds an overhead fee to operate those underlying properties for which Whiting is designated as the operator consistent with the applicable operating agreements. Additionally, for those underlying properties for which Whiting is designated the operator but there is no operating agreement covering such underlying property, Whiting will deduct from the gross proceeds an overhead fee to operate such underlying properties based on overhead charges allocated by Whiting to such underlying property calculated in the same manner Whiting allocates overhead to other similarly owned property. The operating activities include various engineering, accounting and administrative functions. The fee is based on a monthly charge per active operated well and Whiting’s portion totaled $2.1 million for the twelve months ending September 30, 2007 for all of the underlying properties. The fee is adjusted annually pursuant to COPAS guidelines and will increase or decrease each year based on changes in the year-end index of average weekly earnings of crude petroleum and natural gas workers.

In the event that the net proceeds for any computation period is a negative amount, the trust will receive no payment for that period, and any such negative amount plus accrued interest at the prevailing money market rate will be deducted from gross proceeds in the following computation period for purposes of determining the net proceeds for that following computation period.

Gross proceeds and net proceeds are calculated on a cash basis, except that certain costs, primarily ad valorem taxes and expenditures of a material amount, may be determined on an accrual basis.

Additional Provisions

If a controversy arises as to the sales price of any production, then for purposes of determining gross proceeds:


	•	amounts withheld or placed in escrow by a purchaser are not considered to be received by Whiting until actually collected;

	•	amounts received by Whiting and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to it by the escrow agent; and

	•	amounts received by Whiting and not deposited with an escrow agent will be considered to have been received.

The trustee is not obligated to return any cash received from the net profits interest. Any overpayments made to the trust by Whiting due to adjustments to prior calculations of net proceeds or otherwise will reduce future amounts payable to the trust until Whiting recovers the overpayments plus interest at the prevailing money market rate.

In addition, Whiting may, without the consent of the trust unitholders, require the trust to release the net profits interest associated with any well or lease that accounts for less than or equal to 0.25% of the total production from the underlying properties in the prior 12 months and provided that the net profits interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the trust of $500,000. These releases will be made only in connection with a sale by Whiting of the relevant underlying properties and are conditioned upon the trust receiving an amount equal to the fair value to the trust of such net profits interest. Any net sales proceeds paid to the trust are distributable to trust unitholders for the quarter in which they are received. Whiting has not identified for sale any of the underlying properties.

As the designated operator of underlying properties, Whiting may enter into farm-out, operating, participation and other similar agreements with respect to the property. Whiting may enter into any of these agreements without the consent or approval of the trustee or any trust unitholder.

Whiting will have the right to abandon any well or property if it reasonably believes the well or property ceases to produce or is not capable of producing in commercially paying quantities. In making such decisions, Whiting is required under the applicable conveyance to operate the underlying properties as a reasonably prudent operator in the same manner it would if these properties were not burdened by the net profits interest. Upon termination of the lease, the portion of the net profits interest relating to the abandoned property will be extinguished.

Whiting must maintain books and records sufficient to determine the amounts payable for the net profits interest to the trust. Quarterly and annually, Whiting must deliver to the trustee a statement of the computation of the net proceeds for each computation period. The trustee has the right to inspect and copy the books and records maintained by Whiting during normal business hours and upon reasonable notice.

DESCRIPTION OF THE TRUST AGREEMENT

The following information and the information included under “Description of the Trust Units” summarize the material information contained in the trust agreement and the conveyance. For more detailed provisions concerning the trust and the conveyance, you should read the trust agreement and the conveyance. Copies of the trust agreement and the conveyance have been filed as exhibits to the registration statement. See “Where You Can Find More Information.”

Creation and Organization of the Trust; Amendments

Prior to the closing of this offering, Whiting Petroleum Corporation’s wholly-owned subsidiaries, Whiting Oil and Gas Corporation and Equity Oil Company, will convey the net profits interest to the trust in consideration for the issuance by the trust of trust units, which will be distributed as a dividend to Whiting Petroleum Corporation. The first quarterly distribution is expected to be made prior to or on February 29, 2008 to trust unitholders owning trust units on February 19, 2008. The trust’s first quarterly distribution will consist of an amount in cash paid by Whiting equal to the amount that would have been payable to the trust had the net profits interest been in effect during the period from October 1, 2007 through December 31, 2007. The second quarterly distribution is expected to be made prior to or on May 30, 2008 to trust unitholders owning trust units on May 20, 2008. The trust’s second quarterly distribution will consist of an amount in cash paid by Whiting equal to the amount that would have been payable to the trust had the net profits interest been in effect during the period from January 1, 2008 through the day prior to close of this offering plus the amount payable under the net profits interest for the period from the day of closing of the offering through March 31, 2008.

The amount of quarterly cash distributions will be based on the amount of cash relating to the underlying properties that has been received and processed by Whiting and then remitted to the trustee during the applicable quarter. After the offering made hereby, Whiting will own its net interests in the underlying properties subject to and burdened by the net profits interest. The trust will be entitled to receive 90% of the net proceeds from the sale of oil, natural gas and natural gas liquid volumes produced from the underlying properties calculated in accordance with the terms of the conveyance. Also, the trust will be entitled to receive 90% of all amounts paid to Whiting from the hedge contract counterparties upon settlements of the hedge contracts, subject to certain restrictions as discussed in more detail in “Computation of Net Proceeds.” Additionally, the amount of net proceeds to the trust will be reduced by 90% of all payments made by Whiting to hedge contract counterparties upon settlement of the hedge contracts and all other costs paid to counterparties under the hedge contracts or to the persons that provide credit to maintain the hedge contracts.

The trust was created under Delaware law to acquire and hold the net profits interest for the benefit of the trust unitholders pursuant to an agreement between Whiting, the trustee and the Delaware trustee. The net profits interest is passive in nature and neither the trust nor the trustee has any control over or responsibility for costs relating to the operation of the underlying properties. Neither Whiting nor other operators of the underlying properties have any contractual commitments to the trust to provide additional funding or to conduct further drilling on or to maintain their ownership interest in any of these properties. After the conveyance of the net profits interest, however, Whiting will retain an interest in each of the underlying properties. For a description of the underlying properties and other information relating to them, see “The Underlying Properties.”

The beneficial interest in the trust is divided into trust units. Each of the trust units represents an equal undivided beneficial interest in the assets of the trust. You will find additional information concerning the trust units in “Description of the Trust Units.”

Amendment of the trust agreement requires a vote of holders of a majority of the outstanding trust units. However, no amendment may:


	•	increase the power of the trustee or the Delaware trustee to engage in business or investment activities; or

	•	alter the rights of the trust unitholders as among themselves.

Certain amendments to the trust agreement do not require the vote of the trust unitholders. The trustee may, without approval of the trust unitholders, from time to time supplement or amend the trust agreement in order to cure any ambiguity, to correct or supplement any defective or inconsistent provisions, to grant any benefit to all of the trust unitholders or to change the name of the trust, provided such supplement or amendment is not adverse to the interest of the trust unitholders. The business and affairs of the trust will be managed by the trustee. Whiting has no ability to manage or influence the operations of the trust.

Assets of the Trust

Upon completion of this offering, the assets of the trust will consist of the net profits interest and any cash and temporary investments being held for the payment of expenses and liabilities and for distribution to the trust unitholders.

Duties and Powers of the Trustee

The duties of the trustee are specified in the trust agreement and by the laws of the State of Delaware, except as modified by the trust agreement. The trustee’s principal duties consist of:


	•	collecting cash attributable to the net profits interest and received upon settlement of the hedge contracts;

	•	paying expenses, charges and obligations of the trust from the trust’s assets;

	•	distributing distributable cash to the trust unitholders;

	•	causing to be prepared and distributed a tax information report for each trust unitholder and to prepare and file tax returns on behalf of the trust;

	•	causing to be prepared and filed reports required to be filed under the Securities Exchange Act of 1934 and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading;

	•	establishing, evaluating and maintaining a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002;

	•	enforcing the rights under certain agreements entered into in connection with this offering; and

	•	taking any action it deems necessary and advisable to best achieve the purposes of the trust.

In connection with the formation of the trust, the trustee entered into several agreements with Whiting that impose obligations upon Whiting that are enforceable by the trustee on behalf of the trust. For example, when making decisions with respect to the operation, abandonment or sale of the underlying properties, Whiting is obligated under the terms of the conveyance of the net profits interest to operate the underlying properties as a reasonably prudent operator in the same manner it would if these properties were not burdened by the net profits interest. In addition, the trust has entered into an administrative services agreement with Whiting pursuant to which Whiting has agreed to perform specified administrative services on behalf of the trust in a good and workmanlike manner in accordance with the sound and prudent practices of providers of similar services. The trustee has the power and authority under the trust agreement to enforce these agreements on behalf of the trust.

If a trust liability is contingent or uncertain in amount or not yet currently due and payable, the trustee may create a cash reserve to pay for the liability. If the trustee determines that the cash on hand and the cash

to be received are insufficient to cover the trust’s liability, the trustee may borrow funds required to pay the liabilities. The trustee may borrow the funds from any person, including itself or its affiliates. The trustee may also mortgage the assets of the trust to secure payment of the indebtedness. The terms of such indebtedness and security interest, if funds were loaned by the entity serving as trustee or Delaware trustee or an affiliate thereof, would be similar to the terms which such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship, and such entity shall be entitled to enforce its rights with respect to any such indebtedness and security interest as if it were not then serving as trustee or Delaware trustee. If the trustee borrows funds, the trust unitholders will not receive distributions until the borrowed funds are repaid.

Each quarter, the trustee will pay trust obligations and expenses and distribute to the trust unitholders the remaining proceeds received from the net profits interest. The cash held by the trustee as a reserve against future liabilities or for distribution at the next distribution date must be invested in:


	•	interest bearing obligations of the United States government;

	•	money market funds that invest only in United States government securities;

	•	repurchase agreements secured by interest-bearing obligations of the United States government; or

	•	bank certificates of deposit.

The trust may not acquire any asset except the net profits interest, cash and temporary cash investments, and it may not engage in any investment activity except investing cash on hand.

The trust may merge or consolidate with or into one or more limited partnerships, general partnerships, corporations, business trusts, limited liability companies, or associations or unincorporated businesses if such transaction is agreed to by the trustee and by the affirmative vote of the holders of a majority of the outstanding trust units and such transaction is permitted under the Delaware Statutory Trust Act and any other applicable law.

Whiting may request that the trustee sell certain of its net profits interest under any of the following circumstances:


	•	the sale does not involve a material part of the trust’s assets and is in the best interests of the trust unitholders; or

	•	the sale constitutes a material part of the trust’s assets and is in the best interests of the trust unitholders, subject to the holders representing a majority of the outstanding trust units approving the sale.

Upon dissolution of the trust, the trustee must sell the net profits interest. No trust unitholder approval is required in this event.

The trustee will distribute the net proceeds from any sale of the net profits interest and other assets to the trust unitholders.

The trustee may require any trust unitholder to dispose of his trust units if an administrative or judicial proceeding seeks to cancel or forfeit any of the property in which the trust holds an interest because of the nationality or any other status of that trust unitholder. If a trust unitholder fails to dispose of his trust units, the trustee has the right to purchase them and to borrow funds to make that purchase.

The trustee is not expected to maintain a website for filings made by the trust with the SEC.

The trustee may agree to modifications of the terms of the conveyance or to settle disputes involving the conveyance. The trustee may not agree to modifications or settle disputes involving the net profits interest part of the conveyance if these actions would change the character of the net profits interest in such a way that the net profits interest becomes a working interest or that the trust becomes an operating business.

Liabilities of the Trust

Because the trust does not conduct an active business and the trustee has little power to incur obligations, it is expected that the trust will only incur liabilities for routine administrative expenses, such as the trustee’s fees and accounting, engineering, legal, tax advisory and other professional fees.

Fees and Expenses

The trust will be responsible for paying all legal, accounting, tax advisory, engineering and stock exchange fees, printing costs and other administrative and out-of-pocket expenses incurred by or at the direction of the trustee or the Delaware trustee. These trust administrative expenses are anticipated to aggregate approximately $900,000 per year, although such costs could be greater or less depending on future events that cannot be predicted. Included in the $900,000 annual estimate is an annual administrative fee of $160,000 for the trustee and an annual administrative fee of $3,500 for the Delaware trustee. The trust will pay an annual administrative fee to Whiting, which fee will total $200,000 per year. See “The Trust — Administrative Services Agreement.” The trust will also pay, out of the first cash payment received by the trust, the trustee’s and Delaware trustee’s legal expenses incurred in forming the trust as well as the Delaware trustee’s acceptance fee in the amount of $3,500. These costs will be deducted by the trust before distributions are made to trust unitholders.

Fiduciary Responsibility and Liability of the Trustee

The trustee will not make business decisions affecting the assets of the trust except to the extent it enforces its rights under the conveyance agreement related to the net profits interest and the administrative services agreement described above under “— Duties and Powers of the Trustee” that will be executed in connection with this offering. Therefore, substantially all of the trustee’s functions under the trust agreement are expected to be ministerial in nature. See “— Duties and Powers of the Trustee,” above. The trust agreement, however, provides that the trustee may:


	•	charge for its services as trustee;

	•	retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the trustee to the extent permitted by law);

	•	lend funds at commercial rates to the trust to pay the trust’s expenses; and

	•	seek reimbursement from the trust for its out-of-pocket expenses.

In discharging its duty to trust unitholders, the trustee may act in its discretion and will be liable to the trust unitholders only for its own fraud, gross negligence or acts or omissions constituting bad faith. The trustee will not be liable for any act or omission of its agents or employees unless the trustee acted in bad faith or with gross negligence in their selection and retention. The trustee will be indemnified individually or as the trustee for any liability or cost that it incurs in the administration of the trust, except in cases of fraud, gross negligence or bad faith. The trustee will have a lien on the assets of the trust as security for this indemnification and its compensation earned as trustee. Trust unitholders will not be liable to the trustee for any indemnification. See “Description of the Trust Units — Liability of Trust Unitholders.” The trustee must ensure that all contractual liabilities of the trust are limited to the assets of the trust and the trustee will be liable for its failure to do so.

The trustee may consult with counsel, accountants, tax advisors, geologists, engineers and other parties the trustee believes to be qualified as experts on the matters for which advice is sought. The trustee will be protected for any action it takes in good faith reliance upon the opinion of the expert.

Except as expressly set forth in the trust agreement, neither the trustee, the Delaware trustee nor the other indemnified parties have any duties or liabilities, including fiduciary duties, to the trust or any trust unitholder. The provisions of the trust agreement, to the extent they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties of these persons otherwise existing at law or in equity, are agreed by the trust unitholders to replace such other duties and liabilities of these persons.

Termination of the Trust; Sale of the Net Profits Interest


	•	the trust sells the net profits interest;

	•	annual gross proceeds attributable to the net profits interest are less than $1 million for each of two consecutive years;

	•	the holders of a majority of the outstanding trust units vote in favor of dissolution; or

	•	judicial dissolution of the trust.

The trustee would then sell all of the trust’s assets, either by private sale or public auction, and distribute the net proceeds of the sale to the trust unitholders.

Dispute Resolution

Any dispute, controversy or claim that may arise between Whiting and the trustee relating to the trust will be submitted to binding arbitration before a tribunal of three arbitrators.

Compensation of the Trustee and the Delaware Trustee

The trustee’s and the Delaware trustee’s compensation will be paid out of the trust’s assets. See “— Fees and Expenses.”

Miscellaneous

The principal offices of the trustee are located at 919 Congress Avenue, Suite 500, Austin, Texas 78701, and its telephone number is (512) 236-6599.

The Delaware trustee and the trustee may resign at any time or be removed with or without cause at any time by a vote of not less than a majority of the outstanding trust units. Any successor must be a bank or trust company meeting certain requirements including having combined capital, surplus and undivided profits of at least $20,000,000, in the case of the Delaware trustee, and $100,000,000, in the case of the trustee.

DESCRIPTION OF THE TRUST UNITS

Each trust unit is a unit of the beneficial interest in the trust and is entitled to receive cash distributions from the trust on a pro rata basis. Each trust unitholder has the same rights regarding each of his or her trust units as every other trust unitholder has regarding his or her units. The trust units will be in book-entry form only and will not be represented by certificates. The trust will have trust units outstanding upon completion of this offering.

Distributions and Income Computations

Each quarter, the trustee will determine the amount of funds available for distribution to the trust unitholders. Available funds are the excess cash, if any, received by the trust from the net profits interest, payments from the hedge contracts and other sources (such as interest earned on any amounts reserved by the trustee) that quarter, over the trust’s liabilities for that quarter. Available funds will be reduced by any cash the trustee decides to hold as a reserve against future liabilities. It is expected that quarterly cash distributions during the term of the trust will be made by the trustee no later than 60 days following the end of each quarter (or the next succeeding business day) to the trust unitholders of record on the 50th day following the end of each quarter.

Unless otherwise advised by counsel or the IRS, the trustee will treat the income and expenses of the trust for each quarter as belonging to the trust unitholders of record on the quarterly record date. Trust unitholders will recognize income and expenses for tax purposes in the quarter the trust receives or pays those amounts, rather than in the quarter the trust distributes them. Minor variances may occur. For example, the trustee could establish a reserve in one quarter that would not result in a tax deduction until a later quarter. The trustee could also make a payment in one quarter that would be amortized for tax purposes over several quarters. See “Federal Income Tax Consequences.”

Periodic Reports

The trustee will file all required trust federal and state income tax and information returns. The trustee will prepare and mail to trust unitholders annual reports that trust unitholders need to correctly report their share of the income and deductions of the trust. The trustee will also cause to be prepared and filed reports required to be filed under the Securities Exchange Act of 1934, as amended, and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading, and will also cause the trust to comply with all of the provisions of the Sarbanes-Oxley Act, including but not limited to, establishing, evaluating and maintaining a system of internal controls over financial reporting in compliance with the requirements of Section 404 thereof.

Each trust unitholder and his representatives may examine, for any proper purpose, during reasonable business hours, the records of the trust and the trustee.

Liability of Trust Unitholders

Under the Delaware Statutory Trust Act, trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

Voting Rights of Trust Unitholders

The trustee or trust unitholders owning at least 10% of the outstanding trust units may call meetings of trust unitholders. The trust will be responsible for all costs associated with calling a meeting of trust unitholders unless such meeting is called by the trust unitholders, in which case the trust unitholders will be responsible for all costs associated with calling such meeting of trust unitholders. Meetings must be held in such location as is designated by the trustee in the notice of such meeting. The trustee must send written notice of the time and place of the meeting and the matters to be acted upon to all of the trust unitholders at

least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of trust units outstanding must be present or represented to have a quorum. Each trust unitholder is entitled to one vote for each trust unit owned.

Unless otherwise required by the trust agreement, a matter may be approved or disapproved by the vote of a majority of the trust units held by the trust unitholders at a meeting where there is a quorum. This is true, even if a majority of the total trust units did not approve it. The affirmative vote of the holders of a majority of the outstanding trust units is required to:


	•	dissolve the trust;

	•	remove the trustee or the Delaware trustee;

	•	amend the trust agreement (except with respect to certain matters that do not adversely affect the rights of trust unitholders in any material respect);

	•	merge or consolidate the trust with or into another entity; or

	•	approve the sale of all or any material part of the assets of the trust.

In addition, certain amendments to the trust agreement may be made by the trustee without approval of the trust unitholders. See “Description of the Trust Agreement — Creation and Organization of the Trust; Amendments.” The trustee must consent before all or any part of the trust assets can be sold except in connection with the dissolution of the trust or limited sales directed by Whiting in conjunction with its sale of underlying properties.

Comparison of Trust Units and Common Stock

Trust unitholders have more limited voting rights than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for annual or other periodic re-election of the trustee.

You should also be aware of the following ways in which an investment in trust units is different from an investment in common stock of a corporation.


	Trust Units	Common Stock

Voting	The trust agreement provides voting rights to trust unitholders to remove and replace the trustee and to approve or disapprove major trust transactions.	Corporate statutes provide voting rights to stockholders to elect directors and to approve or disapprove major corporate transactions.

Income Tax	The trust is not subject to income tax; trust unitholders are subject to income tax on their pro rata share of trust income, gain, loss and deduction.	Corporations are taxed on their income and their stockholders are taxed on dividends.

Distributions	Substantially all trust revenue is required to be distributed to trust unitholders.	Stockholders receive dividends at the discretion of the board of directors.

Business and Assets	The business of the trust is limited to specific assets with a finite economic life.	A corporation conducts an active business for an unlimited term and can reinvest its earnings and raise additional capital to expand.

Fiduciary Duties	The trustee shall not be liable to the trust unitholders for any of its acts or omissions absent its own fraud, gross negligence or bad faith.	Officers and directors have a fiduciary duty of loyalty to stockholders and a duty to use due care in management and administration of a corporation.

TRUST UNITS ELIGIBLE FOR FUTURE SALE

General

Prior to this offering, there has been no public market for the trust units. Sales of substantial amounts of the trust units in the open market, or the perception that those sales could occur, could adversely affect prevailing market prices.

Upon completion of this offering, there will be outstanding trust units. All of the trust units sold in this offering, or the trust units if the underwriters exercise their option to purchase additional trust units in full, will be freely tradable without restriction under the Securities Act. All of the trust units outstanding other than the trust units sold in this offering (a total of trust units, or trust units if the underwriters exercise their option to purchase additional shares in full) will be “restricted securities” within the meaning of Rule 144 under the Securities Act and may not be sold other than through registration under the Securities Act or pursuant to an exemption from registration, subject to the restrictions on transfer contained in the lock-up agreements described below and in “Underwriting.”

Lock-up Agreements

In connection with this offering, Whiting has agreed, for a period of 180 days after the date of this prospectus, not to offer, sell, contract to sell or otherwise dispose of or transfer any trust units or any securities convertible into or exchangeable for trust units without the prior written consent of Raymond James & Associates, Inc., subject to specified exceptions. See “Underwriting” for a description of these lock-up arrangements. Upon the expiration of these lock-up agreements, trust units, or trust units if the underwriters exercise their option to purchase additional trust units in full, will be eligible for sale in the public market under Rule 144 of the Securities Act, subject to volume limitations and other restrictions contained in Rule 144, or through registration under the Securities Act.

Rule 144

In general, under Rule 144 as currently in effect, beginning 90 days after the date of this prospectus, a person or persons whose trust units are aggregated, who has beneficially owned restricted trust units for at least one year, including the holding period of any prior owner, would be entitled to sell within any three-month period a number of shares that does not exceed the greater of:


	•	1% of the number of trust units then outstanding; or

	•	the average weekly reported trading volume of the trust units on the New York Stock Exchange during the four calendar weeks preceding the filing of a Form 144 with respect to the sale.

Sales under Rule 144 also are subject to manner of sale provisions and notice requirements and to the availability of current public information about Whiting.

Rule 144(k)

Under Rule 144(k), a person who is not deemed to have been an affiliate of the trust at any time during the three months preceding a sale and who has beneficially owned the trust units proposed to be sold for at least two years, including the holding period of any prior owner (other than an affiliate of the trust) is entitled to sell those shares without complying with the manner of sale, public information, volume limitation or notice provisions of Rule 144.

Registration Rights

The trust intends to enter into a registration rights agreement with Whiting in connection with Whiting’s contribution to the trust of the net profits interest. In the registration rights agreement, the trust will agree, for

the benefit of Whiting and any transferee of its trust units (each, a “holder”), to register the trust units it holds. Specifically, the trust will agree:


	•	subject to the restrictions described above under “— Lock-up Agreements” and under “Underwriting — Lock-up Agreements,” to use its reasonable best efforts to file a registration statement, including, if so requested, a shelf registration statement, with the SEC as promptly as practicable following receipt of a notice requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable trust units;

	•	to use its reasonable best efforts to cause the registration statement or shelf registration statement to be declared effective under the Securities Act as promptly as practicable after the filing thereof; and

	•	to continuously maintain the effectiveness of the registration statement under the Securities Act for 90 days (or for three years if a shelf registration statement is requested) after the effectiveness thereof or until the trust units covered by the registration statement have been sold pursuant to such registration statement or until all registrable trust units:


	•	have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities;”

	•	have been sold in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee of the trust units; or

	•	become eligible for resale pursuant to Rule 144(k) (or any similar rule then in effect under the Securities Act).

The holders will have the right to require the trust to file up to three registration statements and will have piggyback registration rights in certain circumstances.

In connection with the preparation and filing of any registration statement, Whiting will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the trust, which will be borne by the trust, and any underwriting discounts and commissions, which will be borne by the seller of the trust units.

FEDERAL INCOME TAX CONSEQUENCES

U.S. Federal Tax Income Consequences

The following is a discussion of the material U.S. federal income tax considerations that may be relevant to prospective trust unitholders and, unless otherwise noted in the following discussion, expresses the opinion of Foley & Lardner LLP, insofar as it relates to matters of law and legal conclusions. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing (and to the extent noted proposed) Treasury regulations thereunder, and current administrative rulings and court decisions, all of which are subject to change or different interpretation at any time, possibly with retroactive effect. Subsequent changes in such authorities may cause the U.S. federal income tax consequences to vary substantially from the consequences described below. No attempt has been made in the following discussion to comment on all U.S. federal income tax matters affecting the trust or the trust unitholders.

The following discussion is limited to trust unitholders who purchase the trust units upon the initial issuance at the initial issue price (which will equal the first price at which a substantial amount of trust units are sold to the public for cash) and who hold the trust units as “capital assets” (generally, property held for investment). All references to “trust unitholders” (including U.S. trust unitholders and non-U.S. trust unitholders) are to beneficial owners of the trust units. This summary does not address the effect of the U.S. federal estate or gift tax laws or the tax considerations arising under the law of any state, local or foreign jurisdiction. Moreover, the discussion has only limited application to trust unitholders subject to specialized tax treatment such as, without limitation:


	•	banks, insurance companies or other financial institutions;

	•	trust unitholders subject to the alternative minimum tax;

	•	tax-exempt organizations;

	•	dealers in securities or commodities;

	•	regulated investment companies;

	•	traders in securities that elect to use a mark-to-market method of accounting for their securities holdings;

	•	non-U.S. trust unitholders (as defined below) that are “controlled foreign corporations” or “passive foreign investment companies”;

	•	persons that are S-corporations, partnerships or other pass-through entities;

	•	persons that own their interest in the trust units through S-corporations, partnerships or other pass-through entities;

	•	persons that at any time own more than 5% of the aggregate fair market value of the trust units;

	•	certain former citizens or long-term residents of the United States;

	•	U.S. trust unitholders (as defined below) whose functional currency is not the U.S. dollar;

	•	persons who hold the trust units as a position in a hedging transaction, “straddle,” “conversion transaction” or other risk reduction transaction; or

	•	persons deemed to sell the trust units under the constructive sale provisions of the Code.

Prospective investors are urged to consult their own tax advisors as to the particular tax consequences to them of the ownership and disposition of an investment in trust units, including the applicability of any U.S. federal income, federal estate or gift tax, state, local and foreign tax laws, changes in applicable tax laws and any pending or proposed legislation.

As used herein, the term “U.S. trust unitholder” means a beneficial owner of trust units that for U.S. federal income tax purposes is:


	•	an individual who is a citizen of the United States or who is resident in the United States for U.S. federal income tax purposes,

	•	a corporation, or an entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States, a state thereof or the District of Columbia,

	•	an estate the income of which is subject to U.S. federal income taxation regardless of its source, or

	•	a trust if it is subject to the primary supervision of a U.S. court and the control of one or more United States persons (as defined for U.S. federal income tax purposes) or that has a valid election in effect under applicable U.S. Treasury regulations to be treated as a United States person.

The term “non-U.S. trust unitholder” means any beneficial owner of a trust unit (other than an entity that is classified for U.S. federal income tax purposes as a partnership or as a “disregarded entity”) that is not a U.S. trust unitholder.

If an entity that is classified for U.S. federal income tax purposes as a partnership or as a “disregarded entity” is a beneficial owner of trust units, the tax treatment of a member of the entity will depend upon the status of the member and the activities of the entity. Any entity that is classified for U.S. federal income tax purposes as a partnership or as a “disregarded entity” and that is a beneficial owner of trust units, and the members of such an entity, should consult their own tax advisors about the U.S. federal income tax consequences of purchasing, owning, and disposing of trust units.

Classification and Taxation of the Trust

In the opinion of Foley & Lardner LLP, for U.S. federal income tax purposes, the trust will be treated as a grantor trust and not as an unincorporated business entity. As a grantor trust, the trust will not be subject to tax at the trust level. Rather, the grantors, who in this case are the trust unitholders, will be considered to own and receive the trust’s assets and income and will be directly taxable thereon as though no trust were in existence.

No ruling has been or will be requested from the Internal Revenue Service (“IRS”) with respect to the U.S. federal income tax treatment of the trust, including a ruling as to the status of the trust as a grantor trust or as a partnership for U.S. federal income tax purposes. Thus, no assurance can be provided that the opinions and statements set forth in this discussion of U.S. federal income tax consequences would be sustained by a court if contested by the IRS.

The remainder of the discussion below is based on Foley & Lardner LLP’s opinion that the trust will be classified as a grantor trust for federal income tax purposes.

Direct Taxation of Trust Unitholders

Because the trust will be treated as a trust for U.S. federal income tax purposes, trust unitholders will be treated for such purposes as owning a direct interest in the assets of the trust, and each trust unitholder will be taxed directly on his pro rata share of the income and gain attributable to the assets of the trust and will be entitled to claim his pro rata share of the deductions and expenses attributable to the assets of the trust (subject to certain limitations discussed below). The trust will file information returns, reporting to the trust unitholders all items of income, gain, loss, deduction and credit, which must be included in the tax returns of the trust unitholders based on their respective methods of accounting and tax years without regard to the accounting method and tax year of the trust.

Following the end of each quarter, the trustee will determine the amount of funds available as of the end of such quarter for distribution to the trust unitholders and will make distributions of available funds, if any, to the unitholders on or about the 60th day following the end of the quarter to the unitholders of record on the 50th day following the end of the quarter. In certain circumstances, however, a trust unitholder will not receive

the distribution attributable to such income. For example, if the trustee establishes a reserve or borrows money to satisfy liabilities of the trust, income associated with the cash used to establish that reserve or to repay that loan must be reported by the trust unitholder, even though that cash is not distributed to him.

As described above, the trust will allocate items of income, gain, loss, deductions and credits to trust unitholders based on record ownership at the quarterly record dates. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the unitholders affected by the issue and result in an increase in the administrative expense of the trust in subsequent periods.

Classification of the Net Profits Interest

Based on representations made by Whiting regarding the expected economic life of the underlying properties and the expected duration of the net profits interest, the net profits interest should be treated as a “production payment” under Section 636 of the Code or otherwise as a debt instrument for U.S. federal income tax purposes. Thus, each trust unitholder should be treated as making a loan to Whiting in an aggregate amount generally equal to the purchase price of the trust units, and proceeds payable to the trust from the sale of production from the burdened properties should be treated as payments of principal and interest on a debt instrument issued by Whiting.

Whiting will treat the net profits interest as indebtedness subject to the Treasury Regulations applicable to contingent payment debt instruments (the “CPDI regulations”), and by purchasing trust units, each trust unitholder will agree to be bound by our application of the CPDI regulations, including our determination of the rate at which interest will be deemed to accrue on the net profits interest (treated as a debt instrument for U.S. federal income tax purposes). The remainder of this discussion assumes that the net profits interest will be treated in accordance with that agreement and our determinations. No assurance can be given that the IRS will not assert that the net profits interest should be treated differently. Such different treatment could affect the amount, timing and character of income, gain or loss in respect of an investment in trust units and could require a trust unitholder to accrue interest income at a rate different than the “comparable yield” described below.

Tax Consequences to U.S. Trust Unitholders

Payments of Interest on the Trust Units

Under the CPDI regulations, U.S. trust unitholders generally will be required to accrue income on the net profits interest in the amounts described below, regardless of whether the U.S. trust unitholder uses the cash or accrual method of tax accounting.

The CPDI regulations provide that a U.S. trust unitholder must accrue an amount of ordinary interest income for U.S. federal income tax purposes, for each accrual period prior to and including the maturity date of the debt instrument, that equals:


	•	the product of (i) the adjusted issue price (as defined below) of the debt instrument represented by ownership of trust units as of the beginning of the accrual period; and (ii) the comparable yield to maturity (as defined below) of such debt instrument, adjusted for the length of the accrual period;

	•	divided by the number of days in the accrual period; and

	•	multiplied by the number of days during the accrual period that the trust unitholder held the trust units.

The “issue price” of the debt instrument held by the trust is the first price at which a substantial amount of the trust units is sold to the public, excluding sales to bond houses, brokers or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers. The “adjusted issue price” of such a debt instrument is its issue price increased by any interest income previously accrued, determined without regard to any adjustments to interest accruals described below, and decreased by the projected amount of any payments scheduled to be made with respect to the debt instrument at an earlier time (without regard to the actual amount paid). The term “comparable yield” means the annual yield we would be

expected to pay, as of the initial issue date, on a fixed rate debt security with no contingent payments but with terms and conditions otherwise comparable to those of the debt instrument represented by ownership of trust units.

We intend to take the position that the comparable yield for the debt instrument held by the trust is an annual rate of 9.0%, compounded semi-annually. The CPDI regulations require that we provide to trust unitholders, solely for determining the amount of interest accruals for U.S. federal income tax purposes, a schedule of the projected amounts of payments, which we refer to as projected payments, on the debt instrument held by the trust. These payments set forth on the schedule must produce a total return on such debt instrument equal to its comparable yield. Amounts treated as interest under the CPDI regulations are treated as original issue discount for all purposes of the Code.

As required by the CPDI regulations, for U.S. federal income tax purposes, each holder of trust units must use the comparable yield and the schedule of projected payments as described above in determining its interest accruals, and the adjustments thereto described below, in respect of the debt instrument held by the trust. You may obtain the projected payment schedule by submitting a written request for such information to Whiting Petroleum Corporation at 1700 Broadway, Suite 2300, Denver, Colorado 80290-2300, Attention: Corporate Secretary.

Our determinations of the comparable yield and the projected payment schedule are not binding on the IRS and it could challenge such determinations. If it did so, and if any such challenge were successful, then the amount and timing of interest income accruals of the trust unitholders would be different from those reported by us or included on previously filed tax returns by the trust unitholders.

The comparable yield and the schedule of projected payments are not determined for any purpose other than for the determination for U.S. federal income tax purposes of a trust unitholder’s interest accruals and adjustments thereof in respect of the debt instrument represented by ownership of trust units and do not constitute a projection or representation regarding the actual amounts payable on the trust units.

For U.S. federal income tax purposes, a trust unitholder is required under the contingent payment debt regulations to use the comparable yield and the projected payment schedule established by us in determining interest accruals and adjustments in respect of a unit, unless such trust unitholder timely discloses and justifies the use of a different comparable yield and projected payment schedule to the IRS. Pursuant to the terms of the conveyance, we and every trust unitholder agree (in the absence of an administrative determination or judicial ruling to the contrary) to be bound by our determination of the comparable yield and projected payment schedule.

If, during any taxable year, a U.S. trust unitholder receives actual payments with respect to the debt instrument held by the trust that in the aggregate exceed the total amount of projected payments for that taxable year, the trust unitholder will incur a “net positive adjustment” under the CPDI regulations equal to the amount of such excess. The U.S. trust unitholder will treat a “net positive adjustment” as additional interest income for such taxable year.

If a U.S. trust unitholder receives in a taxable year actual payments with respect to the debt instrument held by the trust that in the aggregate are less than the amount of projected payments for that taxable year, the U.S. trust unitholder will incur a “net negative adjustment” under the CPDI regulations equal to the amount of such deficit. This adjustment will (a) reduce the U.S. trust unitholder’s interest income on the debt instrument held by the trust for that taxable year, and (b) to the extent of any excess after the application of (a) give rise to an ordinary loss to the extent of the trust unitholder’s interest income on such debt instrument during prior taxable years, reduced to the extent such interest was offset by prior net negative adjustments. Any negative adjustment in excess of the amount described in (a) and (b) will be carried forward, as a negative adjustment to offset future interest income in respect of the debt instrument held by the trust or to reduce the amount realized on a sale, exchange, conversion or retirement of such debt instrument.

The trust is not entitled to claim depletion deductions with respect to the burdened properties.

Disposition of Trust Units

For U.S. federal income tax purposes, a sale of trust units will be treated as a sale by the U.S. trust unitholder of his interest in the assets of the trust. Generally, a U.S. trust unitholder will recognize gain or loss on a sale or exchange of trust units equal to the difference between the amount realized and the U.S. trust unitholder’s adjusted tax basis for the trust units sold. A U.S. trust unitholder’s adjusted tax basis in his trust units will be equal to the U.S. trust unitholder’s original purchase price for the trust units, increased by any interest income previously accrued by the U.S. trust unitholder (determined without regard to any adjustments to interest accruals for positive or negative adjustments as described above) and decreased by the amount of any projected payments that have been previously scheduled to be made in respect of the trust units (without regard to the actual amount paid).

Gain recognized upon a sale or exchange of a trust unit attributable to the net profits interest (the amount of which is reduced by any unused adjustments as discussed above) will generally be treated as ordinary interest income. Any loss will be ordinary loss to the extent of interest previously included in income (reduced by any negative adjustments thereto), and thereafter, capital loss (which will be long-term if the trust unit is held for more than one year). Net capital loss may offset no more than $3,000 of ordinary income in the case of individuals and may only be used to offset capital gain in the case of corporations.

Trust Administrative Expenses

Expenses of the trust will include administrative expenses of the trustee. The deductions so allowed may be itemized deductions which may be subject to limitations on deductibility. Under these rules, administrative expenses attributable to the trust units are miscellaneous itemized deductions that generally will have to be aggregated with an individual unitholder’s other miscellaneous itemized deductions. These rules disallow itemized deductions that are less than 2% of a taxpayer’s adjusted gross income, or reduce the amount of itemized deductions that are otherwise allowable by the lesser of (i) 3% of (A) adjusted gross income over (B) $100,000 ($50,000 in the case of a separate return by a married individual) and (ii) 80% of the amount of itemized deductions that are otherwise allowable, or both. It is anticipated that the amount of such administrative expenses will not be significant in relation to the trust’s income.

Backup Withholding and Information Reporting

Payments of principal and interest on, and the proceeds of dispositions of, the trust units, may be subject to information reporting and U.S. federal backup withholding tax if the trust unitholder thereof fails to supply an accurate taxpayer identification number or otherwise fails to comply with applicable U.S. information reporting or certification requirements. Any amounts so withheld will be allowed as a credit against the trust unitholder’s U.S. federal income tax liability and may entitle the trust unitholder to a refund, provided that the required information is timely furnished to the IRS.

Tax Consequences to Non-U.S. Trust Unitholders

The following is a summary of certain material United States federal income tax consequences that will apply to you if you are a non-U.S. trust unitholder. Non-U.S. trust unitholders should consult their own independent tax advisors to determine the U.S. federal, state, local and foreign tax consequences that may be relevant to them.

Payments with Respect to the Trust Units

Interest paid with respect to the net profits interest will be treated as interest, the amount of which is “contingent” on the earnings of Whiting, and thus will not qualify for the “portfolio interest exemption” under Sections 871 and 881 of the Code. As a result, such interest will be subject to U.S. federal withholding tax at a 30% rate unless the non-U.S. trust unitholder is eligible for a lower rate under an applicable income tax treaty or the interest is effectively connected with the non-U.S. trust unitholder’s conduct of a trade or business in the United States, and in either case, the non-U.S. trust unitholder provides appropriate certification. A non-U.S. trust unitholder generally can meet the certification requirement by providing an IRS Form W-8BEN

(in the case of a claim of treaty benefits) or a W-8 ECI (with respect to the non-U.S. trust unitholder’s conduct of a U.S. trade or business).

If a non-U.S. trust unitholder is engaged in a trade or business in the United States, and if payments on or gain realized on a sale or other disposition of a trust unit are effectively connected with the conduct of this trade or business, the non-U.S. trust unitholder, although exempt from U.S. withholding tax (if the appropriate certification is furnished), will generally be taxed in the same manner as a U.S. trust unitholder (see “— Tax Consequences to U.S. Trust Unitholders” above). Any such non-U.S. trust unitholder should consult its own tax advisers with respect to other tax consequences of the ownership of the trust units, including the possible imposition of a 30% branch profits tax in the case of a non-U.S. trust unitholder that is classified for federal income tax purposes as a corporation.

Sale or Exchange of Trust Units

The net profits interest will be treated as “United States real property interests” for U.S. federal income tax purposes. However, as long as the trust units are regularly traded on an established securities market, gain realized by a non-U.S. trust unitholder on a sale of trust units will be subject to federal income tax only if:


	•	the gain is, or is treated as, effectively connected with business conducted by the non-U.S. trust unitholder in the United States, and in the case of an applicable tax treaty, is attributable to a U.S. permanent establishment maintained by the non-U.S. trust unitholder;

	•	the non-U.S. trust unitholder is an individual who is present in the United States for at least 183 days in the year of the sale and certain other conditions are met; or

	•	the non-U.S. trust unitholder owns currently, or owned at certain earlier times, directly or by applying certain attribution rules, more than 5% of the trust units.

A non-U.S. trust unitholder will be subject to U.S. federal income tax on any gain allocable to the non-U.S. trust unitholder upon the sale by the trust of all or any part of the net profits interest, and distributions to the non-U.S. trust unitholder will be subject to withholding of U.S. tax (currently at the rate of 35%) to the extent the distributions are attributable to such gains.

Backup Withholding Tax and Information Reporting

Payments to non-U.S. trust unitholders of interest, and amounts withheld from such payments, if any, generally will be required to be reported to the IRS and to the non-U.S. trust unitholder.

A non-U.S. trust unitholder may be subject to backup withholding tax, currently at a rate of 28%, with respect to payments from the trust and the proceeds from dispositions of trust units, unless such non-U.S. trust unitholder complies with certain certification requirements (usually satisfied by providing a duly completed IRS Form W-8BEN) or otherwise establishes an exemption. Backup withholding is not an additional tax. Any amounts so withheld will be allowed as a credit against the non-U.S. trust unitholder’s U.S. federal income tax liability and may entitle the non-U.S. trust unitholder to a refund, provided that the required information is timely furnished to the IRS.

Payments of the proceeds of a sale of a trust unit effected by the U.S. office of a U.S. or foreign broker will be subject to information reporting requirements and backup withholding unless the non-U.S. trust unitholder properly certifies under penalties of perjury as to its foreign status and certain other conditions are met or the non-U.S. trust unitholder otherwise establishes an exemption. Information reporting requirements and backup withholding generally will not apply to a payment of the proceeds of the sale of a trust unit effected outside of the United States by a foreign office of a broker. However, unless such a broker has documentary evidence in its records that the holder is a non-U.S. trust unitholder and certain other conditions are met, or the non-U.S. trust unitholder otherwise establishes an exemption, information reporting will apply to a payment of the proceeds of the sale of a trust unit effected outside the United States by such a broker if it:


	•	is a United States person;


	•	derives 50% or more of its gross income for certain periods from the conduct of a trade or business in the United States;

	•	is a controlled foreign corporation for U.S. federal income tax purposes; or

	•	is a foreign partnership that, at any time during its taxable year, has more than 50% of its income or capital interests owned by United States persons or is engaged in the conduct of a U.S. trade or business.

Consequences to Tax Exempt Organizations

Employee benefit plans and most other organizations exempt from U.S. federal income tax including IRAs and other retirement plans are subject to U.S. federal income tax on unrelated business taxable income. Because the trust’s income is not expected to be unrelated business taxable income, such a tax-exempt organization is not expected to be taxed on income generated by ownership of trust units so long as the trust units are not treated as debt-financed property within the meaning of Section 514(b) of the Code.

PROSPECTIVE INVESTORS IN TRUST UNITS ARE STRONGLY ENCOURAGED TO CONSULT THEIR OWN TAX ADVISORS WITH RESPECT TO THE TAX CONSEQUENCES TO THEM OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF THE TRUST UNITS IN LIGHT OF THEIR OWN PARTICULAR CIRCUMSTANCES, INCLUDING THE TAX CONSEQUENCES UNDER STATE, LOCAL, FOREIGN AND OTHER TAX LAWS AND THE POSSIBLE EFFECTS OF CHANGES IN UNITED STATES FEDERAL OR OTHER TAX LAWS.

STATE TAX CONSIDERATIONS

The following is intended as a brief summary of certain information regarding state income taxes and other state tax matters affecting individuals who are trust unitholders. Unitholders are urged to consult their own legal and tax advisors with respect to these matters.

Prospective investors should consider state and local tax consequences of an investment in the trust units. The trust will own the net profits interest burdening specified oil and natural gas properties located in the state of North Dakota, Texas, Oklahoma, Arkansas, Montana, Wyoming, Michigan, New Mexico, Alabama, Louisiana, Colorado, Kansas, Utah and Mississippi. These states are listed in this order based on the pre-tax PV10% value in the reserve report.

The income tax laws of North Dakota, Oklahoma, Montana, Michigan, New Mexico, Alabama, Louisiana, Colorado, Utah and Kansas generally conform to federal income tax laws, meaning that for state income tax purposes in those states, the trust should be treated as a grantor trust, a trust unitholder should be considered to own and receive his or her share of the trust’s assets and income, and the net profits interest should be treated as a debt instrument. An individual who is a nonresident in such states generally will not be subject to income tax from such state on the individual’s share of the trust’s income, except to the extent the trust units are employed by such trust unitholder in a trade, business, profession or occupation carried on in such state. In general, an individual trust unitholder will not be deemed to carry on a trade, business, profession or occupation in such state solely by reason of the purchase and sale of trust units for such nonresident’s own account as an investor. An individual who is a resident of such state will be subject to income tax in such state on that individual’s share of the trust’s income. The trust should not be required to withhold income tax from such states on distributions made to an individual resident or nonresident trust unitholder as long as the trust is taxed as a grantor trust under the Code.

Neither Texas nor Wyoming have a state income tax applicable to individuals. The trust should not be required to withhold income tax from such states on distributions made to an individual resident or nonresident trust unitholder as long as the trust is taxed as a grantor trust under the Code.

The trust units may constitute real property or an interest in real property under the inheritance, estate and probate laws of the states where the underlying properties are located.

ERISA CONSIDERATIONS

The Employee Retirement Income Security Act of 1974, as amended, regulates pension, profit-sharing and other employee benefit plans to which it applies. ERISA also contains standards for persons who are fiduciaries of those plans. In addition, the Internal Revenue Code provides similar requirements and standards which are applicable to qualified plans, which include these types of plans, and to individual retirement accounts, whether or not subject to ERISA.

A fiduciary of an employee benefit plan should carefully consider fiduciary standards under ERISA regarding the plan’s particular circumstances before authorizing an investment in trust units. A fiduciary should consider:


	•	whether the investment satisfies the prudence requirements of Section 404(a)(1)(B) of ERISA;

	•	whether the investment satisfies the diversification requirements of Section 404(a)(1)(C) of ERISA; and

	•	whether the investment is in accordance with the documents and instruments governing the plan as required by Section 404(a)(1)(D) of ERISA.

A fiduciary should also consider whether an investment in trust units might result in direct or indirect nonexempt prohibited transactions under Section 406 of ERISA and Internal Revenue Code Section 4975. In deciding whether an investment involves a prohibited transaction, a fiduciary must determine whether there are plan assets in the transaction. The Department of Labor has published final regulations concerning whether or not an employee benefit plan’s assets would be deemed to include an interest in the underlying assets of an entity for purposes of the reporting, disclosure and fiduciary responsibility provisions of ERISA and analogous provisions of the Internal Revenue Code. These regulations provide that the underlying assets of an entity will not be considered “plan assets” if the equity interests in the entity are a publicly offered security. Whiting expects that at the time of the sale of the trust units in this offering, they will be publicly offered securities. Fiduciaries, however, will need to determine whether the acquisition of trust units is a nonexempt prohibited transaction under the general requirements of ERISA Section 406 and Internal Revenue Code Section 4975.

The prohibited transaction rules are complex, and persons involved in prohibited transactions are subject to penalties. For that reason, potential employee benefit plan investors should consult with their counsel to determine the consequences under ERISA and the Internal Revenue Code of their acquisition and ownership of trust units.

SELLING TRUST UNITHOLDER

The following table provides information regarding the selling trust unitholder’s ownership of the trust units. This table assumes the underwriters’ option to purchase additional trust units is not exercised.

Ownership of trust units before offering

Number of trust

Ownership of trust units after offering

Selling Trust Unitholder

Number

Percentage

units being offered

Number

Percentage

Whiting Petroleum Corporation

100.0

21.7

Prior to this offering, there has been no public market for the trust units. Therefore, if Whiting disposes of its retained trust units, the effect of such disposal on future market prices, if any, of market sales of such remaining trust units or the availability of trust units for sale cannot be predicted. Nevertheless, sales of substantial amounts of trust units in the public market could adversely affect future market prices.

UNDERWRITING

Subject to the terms and conditions in an underwriting agreement dated , 2008, the underwriters named below, for whom Raymond James & Associates, Inc., is acting as representative, have severally agreed to purchase from Whiting the number of trust units set forth opposite their names:


		Number of
Underwriter		Trust Units

Raymond James & Associates, Inc.

Total

The underwriting agreement provides that the obligations of the underwriters to purchase and accept delivery of the trust units offered by this prospectus are subject to approval by their counsel of legal matters and to other conditions set forth in the underwriting agreement. The underwriters are obligated to purchase and accept delivery of all of the trust units offered by this prospectus if any of the units are purchased, other than those covered by the option to purchase additional trust units described below.

The underwriters propose to offer the trust units directly to the public at the public offering price indicated on the cover page of this prospectus and to various dealers at that price less a concession not in excess of $ per unit. The underwriters may allow, and the dealers may re-allow, a concession not in excess of $ per unit to other dealers. If all of the trust units are not sold at the public offering price, the underwriters may change the public offering price and other selling terms. The trust units are offered by the underwriters as stated in this prospectus, subject to receipt and acceptance by them. The underwriters reserve the right to reject an order for the purchase of the trust units in whole or in part.

Option to Purchase Additional Trust Units

Whiting has granted the underwriters an option, exercisable for 30 days after the date of this prospectus, to purchase from time to time up to an aggregate of additional trust units to cover over-allotments, if any, at the public offering price less the underwriting discounts and commissions set forth on the cover page of this prospectus. If the underwriters exercise this option, each underwriter, subject to certain conditions, will become obligated to purchase its pro rata portion of these additional units based on the underwriters’ percentage purchase commitment in this offering as indicated in the table above. The underwriters may exercise the option to purchase additional trust units only to cover over-allotments made in connection with the sale of the trust units offered in this offering.

Discounts and Expenses

The following table shows the amount per unit and total underwriting discounts Whiting will pay to the underwriters (dollars in thousands, except per unit). The amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional trust units.

Per Unit

No Exercise

Full Exercise

Initial public offering price

Underwriting discounts and commissions

Proceeds, before expenses, to Whiting

Whiting will pay Raymond James & Associates, Inc. a structuring fee of $ (or $ if the underwriters exercise their option to purchase additional trust units to cover over-allotments) for evaluation, analysis and structuring of the trust.

The other expenses of this offering that are payable by Whiting are estimated to be $ million (exclusive of underwriting discounts and commissions). In no event will the maximum amount of compensation to be paid to members of the Financial Industry Regulatory Authority, or the “FINRA,” in connection with this offering exceed 10% plus 0.5% for bona fide due diligence expenses.

Indemnification

Whiting has agreed to indemnify the underwriters against various liabilities that may arise in connection with this offering, including liabilities under the Securities Act for errors or omissions in this prospectus or the registration statement of which this prospectus is a part. However, Whiting will not indemnify the underwriters if the error or omission was the result of information the underwriters supplied in writing for inclusion in this prospectus or the registration statement. If Whiting cannot indemnify the underwriters, it has agreed to contribute to payments the underwriters may be required to make in respect of those liabilities. Whiting’s contributions would be in the proportion that the proceeds (after underwriting discounts and commissions) that Whiting receives from this offering bear to the proceeds (from underwriting discounts and commissions) that the underwriters receive. If Whiting cannot contribute in this proportion, Whiting will contribute based on its respective faults and benefits, as set forth in the underwriting agreement.

Lock-up Agreements

Subject to specified exceptions, Whiting has agreed with the underwriters, for a period of 180 days after the date of this prospectus, not to offer, sell, contract to sell or otherwise dispose of or transfer any trust units or any securities convertible into or exchangeable for trust units without the prior written consent of Raymond James & Associates, Inc. These agreements also preclude any hedging collar or other transaction designed or reasonably expected to result in a disposition of trust units or securities convertible into or exercisable or exchangeable for trust units. Raymond James & Associates, Inc. may, in its discretion and at any time without notice, release all or any portion of the securities subject to these agreements. Raymond James & Associates, Inc. does not have any present intent or any understanding to release all or any portion of the securities subject to these agreements.

The 180-day period described in the preceding paragraphs will be extended if:


	•	during the last 17 days of the 180-day period, the trust issues a release concerning distributable cash or announces material news or a material event relating to the trust occurs; or

	•	prior to the expiration of the 180-day period, the trust announces that it will release distributable cash results during the 16-day period beginning on the last day of the 180-day period,

in which case the restrictions described in the preceding paragraphs will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release, the announcement of the material news or the occurrence of the material event.

Stabilization

Until this offering is completed, rules of the SEC may limit the ability of the underwriters and various selling group members to bid for and purchase the trust units. As an exception to these rules, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of the trust units, including:


	•	short sales,

	•	syndicate covering transactions,

	•	imposition of penalty bids, and

	•	purchases to cover positions created by short sales.

Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of the trust units while this offering is in progress. Stabilizing transactions may include making short sales of trust units, which involve the sale by the underwriter of a greater number of trust units than it is required to purchase in this offering and purchasing trust units from Whiting or in the open market to cover positions created by short sales. Short sales may be “covered” shorts, which are short positions in an amount not greater than the underwriters’ option to purchase additional trust units referred to above, or may be “naked” shorts, which are short positions in excess of that amount.

Each underwriter may close out any covered short position either by exercising its option to purchase additional trust units, in whole or in part, or by purchasing trust units in the open market. In making this determination, each underwriter will consider, among other things, the price of trust units available for purchase in the open market compared to the price at which the underwriter may purchase trust units pursuant to the option to purchase additional trust units.

A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the trust units in the open market that could adversely affect investors who purchased in this offering. To the extent that the underwriters create a naked short position, they will purchase trust units in the open market to cover the position.

The underwriters also may impose a penalty bid on selling group members. This means that if the underwriters purchase trust units in the open market in stabilizing transactions or to cover short sales, the underwriters can require the selling group members that sold those trust units as part of this offering to repay the selling concession received by them.

As a result of these activities, the price of the trust units may be higher than the price that otherwise might exist in the open market. If the underwriters commence these activities, they may discontinue them without notice at any time. The underwriters may carry out these transactions on the New York Stock Exchange or otherwise.

Conflicts/Affiliates

The underwriters and their affiliates may provide in the future investment banking, financial advisory or other financial services for Whiting and its affiliates, for which they may receive advisory or transaction fees, as applicable, plus out-of-pocket expenses, of the nature and in amounts customary in the industry for these financial services.

Discretionary Accounts

The underwriters may confirm sales of the trust units offered by this prospectus to accounts over which they exercise discretionary authority but do not expect those sales to exceed 5% of the total trust units offered by this prospectus.

Listing

Whiting intends to apply to list the trust units on the New York Stock Exchange under the symbol “WHX.”

IPO Pricing

Prior to this offering, there has been no public market for the trust units. Consequently, the initial public offering price for the trust units will be determined by negotiations among Whiting and the underwriters. The primary factors to be considered in determining the initial public offering price will be:


	•	estimates of distributions to trust unitholders,

	•	overall quality of the oil and natural gas properties attributable to the underlying properties,

	•	industry and market conditions prevalent in the energy industry,

	•	the information set forth in this prospectus and otherwise available to the representatives and

	•	the general conditions of the securities markets at the time of this offering.

Electronic Prospectus

A prospectus in electronic format may be available on the Internet sites or through other online services maintained by one or more of the underwriters and selling group members participating in this offering, or by

their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the underwriter or the selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with Whiting to allocate a specific number of trust units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or any selling group member’s website and any information contained in any other website maintained by the underwriters or any selling group member is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been approved or endorsed by Whiting or any underwriters or any selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

NASD Conduct Rules

Because the FINRA is expected to view the trust units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules. Investor suitability with respect to the trust units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

LEGAL MATTERS

Richards, Layton & Finger, P.A., as special Delaware counsel to the trust, will give a legal opinion as to the validity of the trust units. Foley & Lardner LLP, will give opinions as to certain other matters relating to the offering, including the tax opinion described in the section of this prospectus captioned “Federal Income Tax Consequences.” Certain legal matters in connection with the trust units will be passed upon for the underwriters by Vinson & Elkins L.L.P.

EXPERTS

The statements of historical revenues and direct operating expenses of the underlying properties for each of the three years in the period ended December 31, 2006, included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein and elsewhere in the registration statement and are included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

The statement of assets and trust corpus of Whiting USA Trust I as of November 16, 2007, included in this prospectus has been audited by Deloitte & Touche LLP, an independent registered public accounting firm as stated in their report appearing herein and elsewhere in the registration statement and is included in reliance upon the reports of such firm as experts in accounting and auditing.

The financial statements and management’s report on the effectiveness of internal control over financial reporting incorporated in this prospectus by reference from Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2006 have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports, which are incorporated herein by reference, and have been so incorporated in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

Certain information appearing in this prospectus regarding the September 30, 2007 estimated quantities of reserves of the underlying properties and net profits interest owned by the trust, the future net revenues from those reserves and their present value is based on estimates of the reserves and present values prepared by or derived from estimates prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers.

Certain information with respect to Whiting’s oil and natural gas reserves derived from the reports of Ryder Scott Company, L.P., Cawley Gillespie & Associates, Inc., and R.A. Lenser & Associates, Inc., each independent petroleum engineering consultants, has been incorporated in this prospectus by reference from Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2006 on the authority of said firms as experts in petroleum engineering.

WHERE YOU CAN FIND MORE INFORMATION

Whiting files annual, quarterly and current reports, proxy statements and other information with the SEC. Whiting and the trust have filed with the SEC a registration statement, including exhibits, under the Securities Act of 1933 with respect to the trust units offered by this prospectus. This prospectus is a part of the registration statement, but does not contain all of the information included in the registration statement or the exhibits. You may read and copy the registration statement and any other document that Whiting files at the SEC’s public reference room at 100 F Street, N.E., Washington D.C. 20549. You can call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference room. You can also find the trust’s and Whiting’s public filings with the SEC on the internet at a web site maintained by the SEC located at http://www.sec.gov.

Whiting is “incorporating by reference” specified documents that Whiting files with the SEC, which means:


	•	incorporated documents are considered part of this prospectus;

	•	Whiting is disclosing important information to you by referring you to those documents; and

	•	information Whiting files with the SEC will automatically update and supersede information contained in this prospectus.

Whiting incorporates by reference the documents listed below and any future filings Whiting makes with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 after the date of this prospectus and before the end of the offering of the securities pursuant to this prospectus:


	•	Whiting’s Annual Report on Form 10-K for the year ended December 31, 2006;

	•	Whiting’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2007, June 30, 2007 and September 30, 2007; and

	•	Whiting’s Current Reports on Form 8-K, dated January 12, 2007, June 21, 2007, June 27, 2007 and October 23, 2007.

Information in this prospectus supersedes related information in the documents listed above, and information in subsequently filed documents supersedes related information in this prospectus and the incorporated documents.

You may request a copy of any of these filings, at no cost, by request directed to Whiting at the following address or telephone number:

Whiting Petroleum Corporation

1700 Broadway, Suite 2300

Denver, Colorado 80290

(303) 837-1661

Attention: Corporate Secretary

You can also find these filings on Whiting’s website at www.whiting.com. However, Whiting is not incorporating the information on Whiting’s website other than these filings into this prospectus.

GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

In this prospectus the following terms have the meanings specified below.

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.

BOE — One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals six Mcf of natural gas and one Bbl of crude oil equals one Bbl of natural gas liquids.

BOE/d — One BOE per day.

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.

Btu or British Thermal Unit — The quantity of heat required to raise the temperature of one pound of water one degree Fahrenheit.

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.

COPAS — The Council of Petroleum Accountants Societies.

Costless collar — An options position where the proceeds from the sale of a call option fund the purchase of a put option.

Differential — The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot, and the wellhead price received.

Estimated Future Net Revenues — Also referred to as “estimated future net cash flows.” The result of applying current prices of oil, natural gas and natural gas liquids to estimated future production from oil, natural gas and natural gas liquids proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves, excluding overhead.

Farm-in or Farm-out Agreement — An agreement under which the owner of a working interest in an oil or natural gas lease typically assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

Field — An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross Acres or Gross Wells — The total acres or wells, as the case may be, in which a working interest is owned.

MBbl — One thousand barrels of crude oil or other liquid hydrocarbons.

MBOE — One thousand BOE.

Mcf — One thousand standard cubic feet of natural gas.

MMBbl — One million barrels of crude oil or other liquid hydrocarbons.

MMBOE — One million BOE.

MMcf — One million cubic feet of natural gas.

Net Acres or Net Wells — The sum of the fractional working interests owned in gross acres or wells, as the case may be.

Net Profits Interest — A nonoperating interest that creates a share in gross production from an operating or working interest in oil and natural gas properties. The share is measured by net profits from the sale of production after deducting costs associated with that production.

Net Revenue Interest — An interest in all oil, natural gas and natural gas liquids produced and saved from, or attributable to, a particular property, net of all royalties, overriding royalties, net profits interests, carried interests, reversionary interests and any other burdens to which the person’s interest is subject.

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.

Pre-tax PV10%— The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Securities and Exchange Commission (“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%. Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC.

Proved Developed Producing Reserves — Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production to market.

Proved Developed Reserves — Has the meaning given to such term in Rule 4-10(a)(3) of Regulation S-X, which defines proved developed reserves as:

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Reserves — Has the meaning given to such term in Rule 4-10(a)(2) of Regulation S-X, which defines proved developed reserves as:

Proved oil and 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 years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following: (A) Oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas,

and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Recompletion — The completion for production of an existing well bore in another formation from which that well has been previously completed.

Reservoir — A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Standardized Measure of Discounted Future Net Cash Flows — Also referred to herein as “standardized measure.” It is the present value of estimated future net revenues computed by discounting estimated future net revenues at a rate of 10% annually.

The Financial Accounting Standards Board requires disclosure of standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities, per paragraph 30 of Statement of Financial Accounting Standards No. 69, as follows:

A standardized measure of discounted future net cash flows relating to an enterprise’s interests in (a) proved oil and gas reserves and (b) oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the enterprise participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves shall be disclosed as of the end of the year. The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. The following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed:

a. Future cash inflows. These shall be computed by applying year-end prices of oil and gas relating to the enterprise’s proved reserves to the year- end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the enterprise’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions, tax credits and allowances relating to the enterprise’s proved oil and gas reserves.

d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

Working Interest — The interest in an crude 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 to share in production, subject to all royalties, overriding royalties and other burdens and to share in all costs of exploration, development and operations and all risks in connection therewith.

Workover — Operations on a producing well to restore or increase production.

Index to Financial Statements


	Page

Underlying Properties:
Report of Independent Registered Public Accounting Firm		F-2
Statements of Historical Revenues and Direct Operating Expenses for Each of the Three Years in the Period Ended December 31, 2006, and the Nine Months Ended September 30, 2006 and 2007 (unaudited)		F-3
Notes to Statements of Historical Revenues and Direct Operating Expenses		F-4

Whiting USA Trust I:
Report of Independent Registered Public Accounting Firm		F-7
Statement of Assets and Trust Corpus as of November 16, 2007		F-8
Notes to Statement of Assets and Trust Corpus		F-9
Unaudited Pro Forma Financial Information		F-11
Unaudited Pro Forma Statements of Assets and Trust Corpus at September 30, 2007		F-12
Unaudited Pro Forma Statements of Distributable Income for the Year Ended
December 31, 2006, and for the Nine Months Ended September 30, 2007		F-13
Notes to Unaudited Pro Forma Financial Information		F-14

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors of

Whiting Petroleum Corporation

Denver, Colorado

We have audited the accompanying statements of historical revenues and direct operating expenses of the Underlying Properties (the “Properties”) of Whiting Petroleum Corporation (the “Company”) for each of the three years in the period ended December 31, 2006. These statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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. The Properties are not required to have, nor were we engaged to perform, an audit of the Properties’ internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Properties’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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.

The accompanying statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in the notes to the statements and are not intended to be a complete presentation of the Company’s interests in the Properties.

In our opinion, the statements referred to above present fairly, in all material respects, the historical revenues and direct operating expenses, described in the notes, of the Properties for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Denver, Colorado

November 16, 2007

F-2

UNDERLYING PROPERTIES

STATEMENTS OF HISTORICAL REVENUES

AND DIRECT OPERATING EXPENSES


							Nine months ended
	Year ended December 31,						September 30,
	2004		2005		2006		2006		2007
							(Unaudited)		(Unaudited)

Revenues:
Oil sales	$	30,539,666	$	43,498,823	$	53,232,066	$	41,058,591	$	41,148,501
Natural gas sales		23,460,243		36,135,271		31,397,455		24,193,531		20,736,595

Total revenues		53,999,909		79,634,094		84,629,521		65,252,122		61,885,096

Direct operating expenses:
Lease operating		10,854,433		16,180,693		21,912,702		15,687,225		16,952,622
Production tax		3,954,703		5,602,452		6,006,308		4,621,121		4,365,517

Total direct operating expenses		14,809,136		21,783,145		27,919,010		20,308,346		21,318,139

Excess of revenues over direct operating expenses	$	39,190,773	$	57,850,949	$	56,710,511	$	44,943,776	$	40,566,957

The accompanying notes are an integral part of these statements.

F-3

UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES
For the years ended December 31, 2004, 2005 and 2006
(information for the nine months ended September 30, 2006 and 2007 is unaudited)


1.	UNDERLYING PROPERTIES

The underlying properties are net interests in oil and natural gas producing properties owned by Whiting Petroleum Corporation’s wholly-owned subsidiaries Whiting Oil and Gas Corporation and Equity Oil Company (“Whiting”) and located in mature producing fields that have established production profiles in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions of the United States. Whiting conveyed to the Whiting USA Trust I (the “Trust”) the right to receive 90% of the term net proceeds from these underlying properties (“Net Profits Interest”), with Whiting retaining title to the underlying properties.

Significant property acquisitions were made by Whiting during the three-year period presented in the accompanying financial statements. The accompanying statements include the historical revenues and direct operating expenses from these acquired properties beginning on the following dates: Equity Oil Company, July 20, 2004; Permian Basin Properties, September 23, 2004; Institutional Partnership Interests, June 23, 2005; Celero Energy, LP, October 4, 2005; and Howard Energy, August 3, 2006.


2.	BASIS OF PRESENTATION

The accompanying statements of historical revenues and direct operating expenses of the underlying properties were derived from the historical accounting records of Whiting and are presented on the accrual basis of accounting before the effects of conveyance of the Net Profits Interest. Revenue from oil, natural gas and natural gas liquid sales is recognized when sold. The statements do not include depreciation, depletion and amortization, general and administrative expenses, interest expense or other expenses of an indirect nature. Such amounts may not be representative of future operations.

Historical financial statements representing financial position, results of operations and cash flows required by generally accepted accounting principles are not presented as such information is not readily available on an individual property basis, and full historical financial statements are not relevant since the Net Profits Interest will be valued by the Trust at Whiting’s historical cost. Accordingly, the statements of historical revenues and direct operating expenses are presented in accordance with Staff Accounting Bulletin Topic 2-D, Financial Statements of Oil and Gas Exchange Offers.

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include accrued revenue and expenses and oil and gas reserves, which are used to derive the standardized measure of discounted future net cash flows. Although management believes these estimates are reasonable, actual results could differ from these estimates.

The accompanying statements of historical revenues and direct operating expenses for the nine months ended September 30, 2006 and 2007 are unaudited. In the opinion of management, the accompanying financial statements include all adjustments necessary to present fairly, in all material respects, the underlying properties’ historical results.


3.	DISCLOSURES ABOUT OIL AND GAS ACTIVITIES (UNAUDITED)

The estimates of proved reserves and related valuations were based on reports prepared by the Company’s independent petroleum engineers Cawley, Gillespie & Associates, Inc, as well as Whiting’s engineering staff. Proved reserve estimates included herein conform to the definitions prescribed by the U.S. Securities and Exchange Commission. The estimates of proved reserves are inherently imprecise and are continually subject

F-4

UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF HISTORICAL REVENUES

AND DIRECT OPERATING EXPENSES — (Continued)

to revision based on production history, results of additional exploration and development, price changes and other factors.

As of December 31, 2006, all of the underlying properties’ oil and gas reserves are attributable to properties within the United States. A summary of the changes in quantities of proved oil and gas reserves for the years ended December 31, 2004, 2005 and 2006, are as follows:


				Natural Gas
	Oil (Mbbl)			(MMcf)

Balance — January 1, 2004		7,295			35,579
Revisions to previous estimates		1,320			460
Purchases of minerals in place		1,240			5,615
Extensions and discoveries		27			6,420
Production		(827	)		(4,268	)

Balance — December 31, 2004		9,055			43,806
Revisions to previous estimates		(207	)		(4,198	)
Purchases of minerals in place		2,014			3,134
Extensions and discoveries		80			1,345
Production		(893	)		(5,082	)

Balance — December 31, 2005		10,049			39,005
Revisions to previous estimates		(657	)		(5,080	)
Purchases of minerals in place		365			1,497
Extensions and discoveries		44			1,525
Production		(946	)		(5,057	)

Balance — December 31, 2006		8,855			31,890

Proved developed reserves:
December 31, 2004		9,037			43,795

December 31, 2005		10,027			38,989

December 31, 2006		8,849			31,546

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 Statement of Financial Accounting Standard No. 69, “Disclosures about Oil and Gas Producing Activities”. 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-5

UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF HISTORICAL REVENUES

AND DIRECT OPERATING EXPENSES — (Continued)

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:


	December 31,
	2004			2005			2006

Future cash inflows	$	549,561,206		$	779,059,917		$	581,795,502
Future production costs		(210,154,598	)		(279,380,789	)		(242,881,527	)
Future development costs		(633,551	)		(547,385	)		(1,001,883	)

Future net cash flows		338,773,057			499,131,743			337,912,092
10% annual discount for estimated timing of cash flows		(136,717,062	)		(220,438,438	)		(138,248,412	)

Standardized measure of discounted future net cash flows	$	202,055,995		$	278,693,305		$	199,663,680

The changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:


	December 31,
	2004			2005			2006

Beginning of year	$	137,099,933		$	202,055,995		$	278,693,305
Sale of oil and gas produced, net of production costs		(39,190,773	)		(57,850,949	)		(56,710,511	)
Net changes in prices and production costs		35,657,031			86,747,963			(42,923,944	)
Extensions, discoveries and improved recovery less related costs		12,873,838			4,326,078			3,512,988
Changes in estimated future development costs, net		(19,082	)		30,323			(301,362	)
Purchases of minerals in place		25,534,481			36,073,563			7,240,015
Revisions of previous quantity estimates		16,390,574			(12,895,268	)		(17,716,142	)
Accretion of discount		13,709,993			20,205,600			27,869,331

End of year	$	202,055,995		$	278,693,305		$	199,663,680

Average prices in effect at December 31, 2004, 2005 and 2006 used in determining future cash inflows related to the standardized measure calculation are as follows:


	2004		2005		2006

Oil (per Bbl)	$	38.94	$	54.75	$	53.18
Gas (per Mcf)	$	5.44	$	7.37	$	4.85

F-6

Report of Independent Registered Public Accounting Firm

To the Unitholders of

Whiting USA Trust I

Denver, Colorado

We have audited the accompanying statement of assets and trust corpus of Whiting USA Trust I (the “Trust”) as of November 16, 2007. This financial statement is the responsibility of the Trust’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit 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 statement of assets and trust corpus is free of material misstatement. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of assets and trust corpus, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall statement of assets and trust corpus presentation. We believe that our audit provides a reasonable basis for our opinion.

As described in Note 2 to the statement of assets and trust corpus, this statement has been prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

In our opinion, the statement of assets and trust corpus presents fairly, in all material respects, the financial position of Whiting USA Trust I as of November 16, 2007, on the basis of accounting described in Note 2.

/s/ Deloitte & Touche LLP

Denver, Colorado

November 16, 2007

F-7

WHITING USA TRUST I

STATEMENT OF ASSETS AND TRUST CORPUS


	November 16, 2007
ASSETS
Cash	$	10

TRUST CORPUS
Trust Corpus	$	10

The accompanying notes are an integral part of this financial statement.

F-8

WHITING USA TRUST I

NOTES TO STATEMENT OF ASSETS AND TRUST CORPUS


1.	ORGANIZATION OF THE TRUST

Whiting USA Trust I (the “Trust”) is a statutory trust formed on October 18, 2007, under the Delaware Statutory Trust Act pursuant to a Trust Agreement (the “Trust Agreement”) among Whiting Oil and Gas Corporation and Equity Oil Company (collectively referred to as “Whiting”) as trustor, The Bank of New York Trust Company, N.A., as Trustee (the “Trustee”), and Wilmington Trust Company, as Delaware Trustee (the “Delaware Trustee”). The initial capitalization of the Trust estate was funded by Whiting on November 16, 2007.

The Trust was created to acquire and hold a term net profits interest for the benefit of the Trust unitholders pursuant to a conveyance from Whiting Oil and Gas Corporation and Equity Oil Company, which are subsidiaries of Whiting Petroleum Corporation (the “Trust Partners”), to the Trust. The term net profits interest is an interest in underlying properties consisting of the Trust’s net interests in all of its oil and natural gas properties located in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions (the “underlying properties”). These oil and gas properties include interests in approximately 3,000 producing oil and gas wells.

The net profits interest is passive in nature and the Trustee will have no management control over and no responsibility relating to the operation of the underlying properties. The net profits interest entitles the Trust to receive 90% of the net proceeds attributable to the Trust’s interest from the sale of production from the underlying properties. The net profits interest will terminate when 9.04 million barrels of oil equivalent have been produced from the underlying properties and sold, and the Trust will soon thereafter wind up its affairs and terminate.

The Trustee can authorize the Trust to borrow money to pay trust administrative or incidental expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee or the Delaware Trustee as a lender provided the terms of the loan are similar to the terms it would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself and make other short term investments with the funds distributed to the Trust.


2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Accounting — The Trust uses the modified cash basis of accounting to report Trust receipts of the term net profits interest and payments of expenses incurred. The term net profits interest is revenues (oil, gas and natural gas liquid sales) less expenses (the amount by which all royalties, lease operating expenses including well workover costs, production and property taxes, payments made by Whiting to hedge counterparties upon settlements of hedge contracts, maintenance expenses, postproduction costs including plugging and abandonment, and producing overhead, exceed hedge payments received by Whiting under hedge contracts and other non-production revenue) of the underlying properties times 90% (term net profits interest percentage). Actual cash receipts may vary due to timing delays of actual cash receipts from the property operators or purchasers and due to wellhead and pipeline volume balancing agreements or practices. The actual cash distributions of the Trust will be made based on the terms of the conveyance creating the Trust’s net profits interest which is on a modified cash basis of accounting.

The financial statements of the Trust as prepared on a modified cash basis reflect the Trust’s assets, liabilities, corpus, earnings, and distributions, as follows:


	a.	Revenues are recorded when received and distributions to Trust unitholders are recorded when paid.

	b.	Trust expenses (which included accounting, engineering, legal, and other professional fees, Trustees’ fees, and out-of-pocket expenses) are recorded when paid.

F-9

WHITING USA TRUST I

NOTES TO STATEMENT OF ASSETS AND TRUST CORPUS — (Continued)


	c.	Cash reserves may be established by the Trustee for certain contingencies that would not be recorded under generally accepted accounting principles.


	d.	Amortization of the investment in net profits interest is calculated based on the units of production method. Such amortization is charged directly to the Trust corpus, and does not affect cash earnings. The Trust evaluates impairment of the investment in net profits interest by comparing the undiscounted cash flows expected to be realized from the investment in net profits interest to the carrying value, pursuant to Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”). If the expected future undiscounted cash flows are less than the carrying value, the Trust recognizes an impairment loss for the difference between the carrying value and the estimated fair value of the investment in net profits interest.

While these statements differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”), the modified cash basis of reporting revenues and distributions is considered to be the most meaningful because quarterly distributions to the Trust unitholders are based on net cash receipts. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with GAAP, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues were received or expenses were paid. Because the Trust’s financial statements are prepared on the modified cash basis, as described above, most accounting pronouncements are not applicable to the Trust’s financial statements.


3.	INCOME TAXES

The Trust is a grantor trust and as such is not subject to income taxes, and accordingly no recognition has been given to income taxes in the Trust’s financial statements. The Trust unitholders are treated as the owners of Trust income and corpus, and the entire taxable income of the Trust will be reported by the Trust unitholders on their respective tax returns.


4.	DISTRIBUTIONS TO UNITHOLDERS

Actual cash distributions to the Trust unitholders will depend upon the quantity of oil, natural gas and natural gas liquids produced from the underlying properties, the prices received for oil, natural gas and natural gas liquid production and other factors. It is expected that quarterly cash distributions during the term of the Trust will be made by the Trustee no later than 60 days following the end of each quarter (or the next succeeding business day) to the Trust unitholders of record on the 50th day following the end of each quarter. Such amounts will be equal to the excess, if any, of the cash received by the Trust during the preceding quarter, over the liabilities of the Trust paid during such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for future liabilities of the Trust.

F-10

WHITING USA TRUST I

UNAUDITED PRO FORMA FINANCIAL INFORMATION

The following unaudited pro forma statement of assets and trust corpus and unaudited pro forma statements of distributable income for the Trust have been prepared to illustrate the conveyance of the term net profits interest in the underlying properties to the Trust by Whiting Oil and Gas Corporation and Equity Oil Company. The unaudited pro forma statement of assets and trust corpus presents the statement of assets and trust corpus of the Trust as of September 30, 2007, giving effect to the net profits interest conveyance as if it occurred on September 30, 2007. The unaudited pro forma statements of distributable income for the year ended December 31, 2006 and the nine months ended September 30, 2007, give effect to the net profits interest conveyance as if it occurred on January 1, 2006, reflecting only pro forma adjustments expected to have a continuing impact on the combined results.

These unaudited pro forma financial statements are for informational purposes only. They do not purport to present the results that would have actually occurred had the net profits interest conveyance been completed on the assumed dates or for the periods presented, or which may be realized in the future.

To produce the pro forma financial information, management made certain estimates. The accompanying unaudited pro forma statement of assets and trust corpus assumes an September 30, 2007 issuance of trust units at $ per unit. The accompanying unaudited pro forma statements of distributable income for the year ended December 31, 2006 and the nine months ended September 30, 2007 have been prepared assuming trust formation and net profits interest conveyance on January 1, 2006.

These estimates are based on the most recently available information. To the extent there are significant changes in these amounts, the assumptions and estimates herein could change significantly. The unaudited pro forma statement of assets and trust corpus and unaudited pro forma statements of distributable income should be read in conjunction with “Discussion and Analysis of Historical Results of the Underlying Properties” and the historical audited statements of the Trust and the Underlying Properties, including the related notes, included in this prospectus and elsewhere in the registration statement.

F-11

WHITING USA TRUST I

UNAUDITED PRO FORMA STATEMENTS OF ASSETS AND TRUST CORPUS
September 30, 2007


			Adjustments
	Historical		(Note 5)			Pro Forma

ASSETS
Cash	$	—	$	10	(a)	$	10
Investment in Net Profits Interest		—		107,639,915	(b)		107,639,915

	$	—	$	107,639,925		$	107,639,925

TRUST CORPUS
Trust Units Issued and Outstanding	$	—	$	107,639,925	(a)(b)	$	107,639,925

The accompanying notes are an integral part of the unaudited pro forma financial information.

F-12

WHITING USA TRUST I

UNAUDITED PRO FORMA STATEMENTS OF DISTRIBUTABLE INCOME


				Nine months
	Year ended			ended
	December 31,			September 30,
	2006			2007

Historical results
Income from Net Profits Interest	$	51,039,460		$	36,510,261
Pro Forma Adjustments
Less trust general and administrative expenses (Note 5)		(200,000	)(c)		(150,000	)(c)

Distributable income		50,839,460			36,360,261

Distributable income per unit	$			$

Trust Units Outstanding

The accompanying notes are an integral part of the unaudited pro forma financial information.

F-13

WHITING USA TRUST I

NOTES TO UNAUDITED PRO FORMA FINANCIAL INFORMATION


1.	BASIS OF PRESENTATION

Whiting USA Trust I (the “Trust”) will own a term net profits interest in oil and gas producing properties located in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions of the United States, and owned by Whiting Oil and Gas Corporation and Equity Oil Company, which are subsidiaries of Whiting Petroleum Corporation (the “Trust Partners”). The term net profits interest entitles the Trust to receive 90% of the net proceeds attributable to the Trust Partners’ interest from the sale of oil and gas production from these properties. The net profits interest will terminate when 9.04 million barrels of oil equivalent have been produced from the underlying properties and sold, and the Trust will soon thereafter wind up its affairs and terminate.

The unaudited pro forma financial information assumes the issuance of trust units at $ per unit.

The Trust was formed on October 18, 2007 under Delaware law to acquire and hold the net profits interest for the benefit of the holders of the Trust units. The net profits interest is passive in nature and the Trustee will have no management control over and no responsibility relating to the operation of the underlying properties.


2.	TRUST ACCOUNTING POLICIES

These unaudited pro forma statements were prepared using the accrual basis information from the historical revenue and direct operating expenses of the underlying properties. The Trust uses the modified cash basis of accounting to report Trust receipts of the term net profits interest and payments of expenses incurred. Actual cash receipts may vary due to timing delays of actual cash receipts from the property operators or purchasers and due to wellhead and pipeline volume balancing agreements or practices. The actual cash distributions of the Trust will be made based on the terms of the conveyance creating the Trust’s net profits interest which is on a modified cash basis of accounting.

Investment in the net profits interest is recorded initially at the historic cost of the Trust Partners in accordance with Staff Accounting Bulletin Topic 5.G, Transfers of Nonmonetary Assets By Promoters Or Shareholders, and is periodically assessed to determine whether its aggregate value has been impaired below its total capitalized cost based on the underlying properties. The Trust will provide a write-down to its investment in the net profits interest to the extent that total capitalized costs, less accumulated depreciation, depletion and amortization, exceed undiscounted future net revenues attributable to the proved oil and gas reserves of the underlying properties.

The Trust Partners believe that the assumptions used provide a reasonable basis for presenting the significant effects directly attributable to this transaction.

This unaudited pro forma financial information should be read in conjunction with the statements of historical revenues and direct operating expenses for underlying properties and related notes for the periods presented.


3.	INCOME TAXES

The Trust is a Delaware statutory trust and is not required to pay federal or state income taxes. Accordingly, no provision for Federal or state income taxes has been made.

F-14

WHITING USA TRUST I

NOTES TO UNAUDITED PRO FORMA FINANCIAL INFORMATION — (Continued)


4.	INCOME FROM NET PROFITS INTEREST


				Nine months
	Year ended			ended
	December 31,			September 30,
	2006			2007

Excess of revenues over direct operating expenses of Underlying Properties	$	56,710,511		$	40,566,957
Times net profits interest over the term of the Trust		90	%		90	%

Income from net profits interest	$	51,039,460		$	36,510,261


5.	PRO FORMA ADJUSTMENTS

(a) The Trust Partners transferred $10 to the Trust on November 16, 2007, constituting the initial capitalization of the Trust estate.

(b) The Trust Partners will convey the net profits interest to the Trust in exchange for trust units.

The net profits interest is recorded at the historical cost of the Trust Partners and is calculated as follows:


Oil and gas properties	$	167,860,938
Accumulated depreciation and depletion		(48,261,032	)

Net predecessor cost of property conveyed		119,599,906
Times 90% net profits interest to Trust	$	107,639,915

(c) The Trust will pay an annual administrative fee to the Trust Partners, which fee will total $200,000.

Additionally, the Trust estimates incurring $900,000 annually for general and administrative expenses, which includes the annual administrative fee to the Trust Partners, legal fees, accounting fees, engineering fees, printing costs and other expenses properly chargeable to the Trust. If the estimated expenses were included in the unaudited pro forma statements of distributable income, the distributable income would be $50,139,460, or $ per unit for the year ended December 31, 2006 and $35,835,261 or $ per unit for the nine months ended September 30, 2007.

F-15

November 8, 2007

Whiting USA Trust I

1700 Broadway, Suite 2300

Denver, Colorado 80290-2300


	Re:	Evaluation Summary — SEC Price *Whiting USA Trust I Interests* Proved Producing Reserves Certain Properties Located in Various States As of September 30, 2007

Pursuant to the Guidelines of the Securities and
Exchange Commission for Reporting Corporate
Reserves and Future Net Revenue

Gentlemen:

As requested, we are submitting our estimates of proved producing reserves and forecasts of economics attributable to the underlying properties, from which a net profits interest will be formed and then conveyed by subsidiaries of Whiting Petroleum Corporation to the Whiting USA Trust I. These certain oil properties are located in North Dakota, Texas, Oklahoma, Arkansas, Montana, Wyoming, Michigan, New Mexico, Alabama, Louisiana, Colorado, Kansas, Utah and Mississippi. Also included in the table below are the proved reserves attributable to the same underlying properties estimated to be produced by December 31, 2017. This report includes results for an SEC pricing scenario. The results of this evaluation are presented in the accompanying tabulations, with a composite summary presented below:


		Proved Developed Producing
				Underlying Properties
		Underlying		Reserves Estimated to be Produced
		Properties		By December 31,
Net Reserves		Full Economic Life		2017

Oil	— Mbbl		8,346.6		5,469.4
Gas	— MMcf		27,081.7		19,891.1
NGL	— Mbbl		316.2		260.5
Equivalent*	— Mbbl		13,176.4		9,045.1
Revenue
Oil	— M$		612,206.6		401,278.8
Gas	— M$		155,221.6		115,068.0
NGL	— M$		15,344.1		12,694.9
Other	— M$		0.0		0.0
Severance Taxes	— M$		60,211.0		40,294.5
Ad Valorem Taxes	— M$		9,355.3		6,010.0
Operating Expenses	— M$		298,151.3		172,655.1
Investments	— M$		0.0		0.0
Net Operating Income	— M$		415,054.7		310,082.0
Discounted @ 10%	— M$		243,535.5		220,534.6


*	Calculated based on an energy equivalent that one Bbl of crude oil equals six Mcf of natural gas and one Bbl of crude oil equals one Bbl of natural gas liquids.

The discounted cash flow value shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc.

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Whiting USA Trust I

November 8, 2007

Page 2

Hydrocarbon Pricing

As requested for the SEC scenario, initial oil and gas prices of $81.66 per bbl Nymex WTI and $6.15 per MMbtu Nymex Henry Hub were adjusted individually to WTI posted pricing at $78.40 per bbl and Houston Ship Channel pricing at $6.085 per MMBtu, as of September 30, 2007. Prices were not escalated in the SEC scenario. Oil price differentials, gas price differentials and heating values were applied as furnished by your office.

Expenses and Taxes

Lease operating expenses and Ad Valorem tax values were forecast as provided by your office. Lease operating expenses were held constant in accordance with SEC guidelines. Severance tax rates were applied at normal state percentages of oil and gas revenue.

Miscellaneous

An on-site field inspection of the properties has not been performed. The mechanical operation or conditions of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included.

The proved reserve classifications used conform to the criteria of the Securities and Exchange Commission (“SEC”). The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties in effect as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions have not been considered. All reserve estimates represent our best judgment based on data available at the time of preparation, and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

The reserve estimates were based on interpretations of factual data furnished by your office. Production data, gas prices, gas price differentials, expense data, tax values and ownership interests were also supplied by you and were accepted as furnished. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data.

Yours very truly,

Cawley, Gillespie & Associates, Inc.

-s- Crawley, Gillespie and Associates Inc.

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Until , 2008 (25 days after the date of this prospectus), federal securities laws may require all dealers that effect transactions in the trust units, whether or not participating in this offering, to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

Trust Units

WHITING USA TRUST I

PROSPECTUS

RAYMOND JAMES

, 2008

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS


Item 13.	*Other Expenses Of Issuance And Distribution*

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby all of which will be paid for by Whiting Petroleum Corporation. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing and the NYSE listing fee, the amounts set forth below are estimates.


Registration fee	$	5,986.50
FINRA filing fee		19,705.00
NYSE listing fee			*
Printing and engraving expenses			*
Fees and expenses of legal counsel			*
Accounting fees and expenses			*
Transfer agent and registrar fees			*
Trustee fees and expenses			*
Miscellaneous			*

Total	$		*


*		To be provided by amendment.


Item 14.	*Indemnification Of Directors And Officers.*

The trust agreement provides that the trustee and its officers, agents and employees shall be indemnified from the assets of the trust against and from any and all liabilities, expenses, claims, damages or loss incurred by it individually or as trustee in the administration of the trust and the trust assets, including, without limitation, any liability, expenses, claims, damages or loss arising out of or in connection with any liability under environmental laws, or in the doing of any act done or performed or omission occurring on account of it being trustee or acting in such capacity, except such liability, expense, claims, damages or loss as to which it is liable under the trust agreement. In this regard, the trustee shall be liable only for fraud or gross negligence or for acts or omissions in bad faith and shall not be liable for any act or omission of any agent or employee unless the trustee has acted in bad faith or with gross negligence in the selection and retention of such agent or employee. The trustee is entitled to indemnification from the assets of the trust and shall have a lien on the assets of the trust to secure it for the foregoing indemnification.

Under the provisions of Section 145 of the Delaware General Corporation Law, Whiting Petroleum Corporation (“the Company”) is required to indemnify any present or former officer or director against expenses arising out of legal proceedings in which the director or officer becomes involved by reason of being a director or officer if the director or officer is successful in the defense of such proceedings. Section 145 also provides that the Company may indemnify a director or officer in connection with a proceeding in which he is not successful in defending if it is determined that he acted in good faith and in a manner reasonably believed to be in or not opposed to the best interests of the Company or, in the case of a criminal action, if it is determined that he had no reasonable cause to believe his conduct was unlawful. Liabilities for which a director or officer may be indemnified include amounts paid in satisfaction of settlements, judgments, fines and other expenses (including attorneys’ fees incurred in connection with such proceedings). In a stockholder derivative action, no indemnification may be paid in respect of any claim, issue or matter as to which the director or officer has been adjudged to be liable to the Company (except for expenses allowed by a court).

The Company’s Amended and Restated Certificate of Incorporation provides for indemnification of directors and officers of the Company to the full extent permitted by applicable law. Under the provisions of the Company’s Amended and Restated By-laws, the Company is required to indemnify officers or directors to

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a greater extent than under the current provisions of Section 145 of the Delaware General Corporation Law. Except with respect to stockholder derivative actions, the By-law provisions generally state that the director or officer will be indemnified against expenses, amounts paid in settlement and judgments, fines, penalties and/or other amounts incurred with respect to any threatened, pending or completed proceeding, provided that (i) such person acted in good faith and in a manner such person reasonably believed to be in or not opposed to the best interests of the Company, and (ii) with respect to any criminal action or proceeding, such person had no reasonable cause to believe his or her conduct was unlawful.

The foregoing standards also apply with respect to the indemnification of expenses incurred in a stockholder derivative suit. However, a director or officer may only be indemnified for settlement amounts or judgments incurred in a derivative suit to the extent that the Court of Chancery or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Court of Chancery or such other court shall deem proper.

In accordance with the Delaware General Corporation Law, the Company’s Amended and Restated Certificate of Incorporation contains a provision to limit the personal liability of the directors of the Company for violations of their fiduciary duty. This provision eliminates each director’s liability to the Company or its stockholders, for monetary damages except (i) for breach of the director’s duty of loyalty to the Company or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) under Section 174 of the Delaware General Corporation Law providing for liability of directors for unlawful payment of dividends or unlawful stock purchases or redemptions or (iv) for any transaction from which a director derived an improper personal benefit. The effect of this provision is to eliminate the personal liability of directors for monetary damages for actions involving a breach of their fiduciary duty of care, including any such actions involving gross negligence.

The Company maintains insurance policies that provide coverage to its directors and officers against certain liabilities.


Item 15.	*Recent Sales Of Unregistered Securities.*

None.


Item 16.	*Exhibits and Financial Statement Schedules.*

(a) Exhibits. The exhibits listed in the accompanying Exhibit Index are filed or incorporated by reference as part of this Registration Statement.

(b) Financial Statement Schedules. No financial statement schedules are required to be included herewith or they have been omitted because the information required to be set forth therein is not applicable.


Item 17.	*Undertakings.*

The undersigned Registrants hereby undertake that, for purposes of determining any liability under the Securities Act of 1933, each filing of Registrant’s annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to Section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The undersigned Registrants hereby undertake to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of each Registrant pursuant to the foregoing provisions, or otherwise,

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each Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by a Registrant of expenses incurred or paid by a director, officer or controlling person of a Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, that Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that, for purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in the form of prospectus filed by the Registrants pursuant to Rule 424(b) (1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.

The undersigned registrant hereby undertakes that, for the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The undersigned Registrants hereby undertake to send to each trust unitholder at least on an annual basis a detailed statement of any transactions with the trustees or their respective affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to the trustees or their respective affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed. The undersigned Registrants hereby undertake to provide to the trust unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the trust.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-3 and has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on November 20, 2007.

WHITING PETROLEUM CORPORATION


	By:	/s/ James J. Volker

James J. Volker

Chairman, President and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities on November 20, 2007.


Signature		Title


/s/ James J. Volker James J. Volker		Chairman, President and Chief Executive Officer and Director (Principal Executive Officer)

/s/ Michael J. Stevens Michael J. Stevens		Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ Brent P. Jensen Brent P. Jensen		Controller and Treasurer (Principal Accounting Officer)

* Thomas L. Aller		Director

* D. Sherwin Artus		Director

* Thomas P. Briggs		Director

* William N. Hahne		Director

* Graydon D. Hubbard		Director

* Palmer L. Moe		Director

* Kenneth R. Whiting		Director

*By	/s/ James J. Volker James J. Volker Attorney-in-fact

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on November 20, 2007.

WHITING USA TRUST I

By: WHITING PETROLEUM CORPORATION


	By:	/s/ James J. Volker

James J. Volker

Chairman, President and Chief Executive Officer

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EXHIBIT INDEX


Exhibit
Number		Document Description

(1)		Form of Underwriting Agreement.*
(3.1)		Amended and Restated Certificate of Incorporation of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 3.1 to Whiting Petroleum Corporation’s Registration Statement on Form S-1 (Registration No. 333-107341)].
(3.2)		Amended and Restated By-laws of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 3.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated February 23, 2006 (File No. 001-31899)].
(3.3)		Certificate of Designations of the Board of Directors Establishing the Series and Fixing the Relative Rights and Preferences of Series A Junior Participating Preferred Stock [Incorporated by reference to Exhibit 3.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated February 23, 2006 (File No. 001-31899)].
(3.4)		Certificate of Trust of Whiting USA Trust I.
(3.5)		Trust Agreement dated October 18, 2007 among Whiting Oil and Gas Corporation, Equity Oil Company, Bank of New York Trust Company, N.A. and Wilmington Trust Company.
(3.6)		Form of Amended and Restated Trust Agreement among Whiting Oil and Gas Corporation, Equity Oil Company, Bank of New York Trust Company, N.A. and Wilmington Trust Company.*
(4.1)		Third Amended and Restated Credit Agreement, dated as of August 31, 2005, among Whiting Oil and Gas Corporation, Whiting Petroleum Corporation, the financial institutions listed therein and JPMorgan Chase Bank, N.A., as Administrative Agent [Incorporated by reference to Exhibit 4 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated August 31, 2005 (File No. 001-31899)].
(4.2)		Indenture, dated May 11, 2004, by and among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, Whiting Programs, Inc., Equity Oil Company and J.P. Morgan Trust Company, National Association [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004 (File No. 001-31899)].
(4.3)		Subordinated Indenture, dated as of April 19, 2005, by and among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, Whiting Programs, Inc., Equity Oil Company and J.P. Morgan Trust Company, National Association [Incorporated by reference to Exhibit 4.4 to Whiting Petroleum Corporation’s Registration Statement on Form S-3 (Reg. No. 333-121615)].
(4.4)		First Supplemental Indenture, dated as of April 19, 2005, by and among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, Equity Oil Company, Whiting Programs, Inc. and J.P. Morgan Trust Company, National Association [Incorporated by reference to Exhibit 4.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated April 11, 2005 (File No. 001-31899)].
(4.5)		Indenture, dated October 4, 2005, by and among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, Whiting Programs, Inc. and JP Morgan Trust Company, National Association [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated October 4, 2005 (File No. 001-31899)].
(4.6)		Rights Agreement, dated as of February 23, 2006, between Whiting Petroleum Corporation and Computershare Trust Company, Inc. [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated February 23, 2006 (File No. 001-31899)].
(5.1)		Opinion of Richards, Layton & Finger, P.A. relating to the validity of the trust units.*
(8.1)		Opinion of Foley & Lardner LLP relating to tax matters.*
(10.1)		Form of Conveyance of Net Profits Interest and Pre-Effective Time Payment.*
(10.2)		Form of Administrative Services Agreement.*
(10.3)		Registration Rights Agreement.*
(23.1)		Consent of Deloitte & Touche LLP with respect to the Underlying Properties and Whiting USA Trust I.
(23.2)		Consent of Cawley, Gillespie & Associates, Inc.
(23.3)		Consent of R.A. Lenser & Associates, Inc.
(23.4)		Consent of Ryder Scott Company, L.P.
(23.5)		Consent of Richards, Layton & Finger, P.A.. (contained in Exhibit 5.1)*
(23.6)		Consent of Foley & Lardner LLP (contained in Exhibit 8.1)*
(23.7)		Consent of Deloitte & Touche LLP with respect to Whiting Petroleum Corporation.
(24)		Powers of Attorney.


*		To be filed by amendment.

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