S-1/A 1 d51039a3sv1za.htm AMENDMENT TO FORM S-1 & S-3 sv1za
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As filed with the Securities and Exchange Commission on April 23, 2008
Registration No. 333-147543      
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
 
 
 
 
     
Amendment No. 3
to
FORM S-1
  Amendment No. 3
to
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
 
 
 
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Whiting USA Trust I
             
Large accelerated filer o
  Accelerated filer o   Non-accelerated filer þ   Smaller reporting company o
        (Do not check if a smaller reporting company)    
Whiting Petroleum Corporation
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    
 
 
 
 
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.
 


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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 April 23, 2008
 
PRELIMINARY PROSPECTUS
 
Whiting USA Trust I
 
10,850,000 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 13,863,889 trust units. The net profits interest will entitle the trust to receive 90% of the net proceeds from the sale of production of 9.11 MMBOE (which is equivalent to 8.20 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 $19.00 and $21.00. The trust units have been approved for listing on the New York Stock Exchange under the symbol “WHX,” subject to official notice of issuance.
 
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 17 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 1,627,500 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 WACHOVIA SECURITIES
 
RBC CAPITAL MARKETS
 
OPPENHEIMER & CO. STIFEL NICOLAUS
 
 
The date of this prospectus is          , 2008


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(Whiting USA Trust I map)
 


 

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 Opinion of Richards, Layton & Finger, P.A.
 Consent of Deloitte & Touche LLP - Underlying Properties
 Consent of Deloitte & Touche LLP - Whiting Petroleum Corporation
 Consent of Cawley, Gillespie & Associates, Inc.
 
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.


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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 December 31, 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 9.11 MMBOE (which is equivalent to 8.20 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 3,051 gross (385.8 net) producing wells located in 172 fields in 14 states. As of December 31, 2007, the total proved reserves attributable to the underlying properties, as estimated in the reserve report, were 13.85 MMBOE with a pre-tax PV10% value of $311.4 million. All of these reserves were classified as proved developed producing reserves. For the month of December 2007, the average daily net production from these properties was approximately 4,643 BOE/d or 4,179 BOE/d attributable to the net profits interest and was approximately 54% oil and natural gas liquids and 46% natural gas. Based on the pre-tax PV10% value in the reserve report, Whiting operates approximately 60.9% 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 9.11 MMBOE have been produced from the underlying properties and sold, which is the equivalent of 8.20 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 9.11 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 9.11 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 the hedge contract counterparty, 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.


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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 April 1, 2008 for oil and May 1, 2008 for natural gas through December 31, 2012. The hedge contracts are priced as follows:
 
                                                 
    Oil Collars     Natural Gas Collars  
          Weighted Average
          Weighted Average
 
    Volumes
    Price (per Bbl)     Volumes
    Price (Per Mcf)  
    (Bbls)     Floor     Ceiling     (Mcf)     Floor     Ceiling  
 
Nine/Eight Months Ending December 31, 2008
    476,280     $ 82.00     $ 133.20       1,928,587     $ 7.00     $ 16.06  
Year Ending December 31, 2009
    577,986     $ 76.00     $ 137.43       2,387,688     $ 6.50     $ 17.11  
Year Ending December 31, 2010
    521,856     $ 76.00     $ 134.98       2,047,068     $ 6.50     $ 15.06  
Year Ending December 31, 2011
    475,368     $ 74.00     $ 140.15       1,803,759     $ 6.50     $ 14.62  
Year Ending December 31, 2012
    434,262     $ 74.00     $ 141.72       1,586,787     $ 6.50     $ 14.27  
 
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.” During the term of the hedge contracts, Whiting expects these contracts will reduce the commodity price-related risks inherent in holding interests in oil and natural gas properties, 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 May 30, 2008 to trust unitholders owning trust units on May 20, 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 January 1, 2008 through March 31, 2008. The second quarterly distribution is expected to be made prior to or on August 29, 2008 to trust unitholders owning trust units on August 19, 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 April 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 June 30, 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


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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 from April 1, 2008 for oil and May 1, 2008 for natural gas through December 31, 2012.
 
  •  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 9.11 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.


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  •  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 counterparty and Whiting. A default by the hedge contract counterparty 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.


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Structure of the Trust
 
The trust will issue 13,863,889 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.
 
(Whiting Flowchart)
 
 
(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 13,863,889 units, which will be distributed as a dividend to Whiting Petroleum Corporation. Whiting Petroleum Corporation is offering 10,850,000 trust units to the public pursuant to this offering. The underwriters may exercise their option to purchase up to 1,627,500 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 68.4% and 17.3%, 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 55.7% and 14.2%, 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 3,051 gross (385.8 net) producing oil and natural gas wells in 172 fields on


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215,376 gross acres in 14 states. Whiting has acquired interests in these properties through various acquisitions that have occurred during its 28 year existence. For the month ended December 2007, the average daily net production from these properties was 4,643 BOE/d (which is equivalent to 4,179 BOE/d attributable to the net profits interest). 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 9.11 MMBOE (which is equivalent to 8.20 MMBOE attributable to the net profits interest) of proved reserves during the term of the trust. The 9.11 MMBOE represents the proved reserves attributable to the underlying properties that the reserve report projects to be produced by December 31, 2017. As of December 31, 2007, proved reserves attributable to the underlying properties, as estimated in the reserve report, were 13.85 MMBOE with a pre-tax PV10% value of $311.4 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 9.11 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 during the term of the trust, 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 December 31, 2007 and the average daily net production attributable to the net profits interest for the month of December 2007.
 
                                                                 
          Proved Reserves (1)     December 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
    62       2,574       2,784       3,038       37.0 %   $ 106.4       42.6 %     1,357  
Mid-Continent
    56       1,535       10,352       3,260       39.8       88.1       35.3       1,598  
Permian Basin
    27       811       2,021       1,148       14.0       35.6       14.2       536  
Gulf Coast
    27       190       3,402       757       9.2       19.7       7.9       688  
                                                                 
Total
    172       5,110       18,559       8,203       100.0 %   $ 249.8       100.0 %     4,179  
                                                                 
 
 
(1) The net profits interest entitles the trust to receive 90% of the net proceeds from the sale of production of 9.11 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 13.85 MMBOE with a pre-tax PV10% value of $311.4 million, although the net profits interest will terminate when 9.11 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


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on NYMEX oil and natural gas prices as of December 31, 2007 of $96.00 per Bbl of oil and $7.10 per Mcf of natural gas less field transportation, quality and basis differentials of $8.34 per Bbl of oil and $0.61 per Mcf of natural gas, resulting in field adjusted prices of $87.66 per Bbl of oil and $6.49 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 December 31, 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 60.9% of these properties were operated by Whiting. Based on December 2007 production attributable to the net profits interest, approximately 54% was oil and natural gas liquids and 46% 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 as well as the Bighorn and Powder River Basins of Wyoming, while the second, from which natural gas is primarily produced, includes southwest Wyoming, Colorado and Utah. These properties include 62 fields of which Whiting operates wells in 32 of these fields. The major North Dakota fields in this region include Bell Field and Fryberg Field that produce from Tyler sandstone; Whiskey Joe, Teddy Roosevelt, Sherwood and Davis Creek Fields that produce from various intervals in the Madison; Hiline Unit that produces from the Lodgepole; and Big Dipper Field that produces from the Duperow and Red River zones. In Montana, the major fields include the Bainville Field and Palomino Fields that produce primarily from the Nisku zone, and Oxbow Field that produces from the Nisku and Red River zones. 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 1,357 BOE/d for the month of December 2007 from 717 gross (105.8 net) 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 56 fields of which Whiting operates wells in 29 of these fields. There are two significant fields located in Arkansas. The Magnolia Smackover Pool Unit, the largest single field in the underlying properties, produces from the Smackover Lime. The second Arkansas field is the Stephens-Smart field, producing from the Buckrange and Travis Peak. 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 1,598 BOE/d for the month of December 2007 from 443 gross (175.3 net) 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 27 fields of which Whiting operates wells in 10 of these fields. The major fields in this region include Iatan East Howard Field, which


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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 536 BOE/d for the month of December 2007 from 1,620 gross (84.3 net) 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 27 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 688 BOE/d for the month of December 2007 from 271 gross (20.4 net) 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 December 2007 production attributable to the net profits interest, approximately 54% 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 10.5% 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 Through December 31, 2012.  For the period from April 1, 2008 for oil and May 1, 2008 for natural gas 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. The crude oil hedge contracts are priced with floors ranging from $74.00 to $82.00 and ceilings ranging from $128.30 to $146.62 per Bbl of oil, and the natural gas hedge contracts are priced with floors ranging from $6.00 to $7.00 and ceilings ranging from $12.45 to $22.50 per Mcf of natural gas. Assuming production occurs as estimated by the reserve report, this would represent approximately 45% of the proved reserves attributable to the net profits interest. The costless collars are intended to provide certain downside price protection while allowing cash flow to be enhanced or maintained during periods of rising commodity prices and corresponding cost increases.
 
  •  Diversified Well Locations.  The underlying properties include interests in 3,051 gross (385.8 net) producing wells in 172 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 25 years of experience in the oil and gas industry. Additionally, Whiting’s personnel have extensive operational experience in each of the core


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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 8.20 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 December 31, 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 December 31, 2007 of $96.00 per Bbl of oil and $7.10 per Mcf of natural gas less field transportation, quality and basis differentials of $8.34 per Bbl of oil and $0.61 per Mcf of natural gas, resulting in field adjusted prices of $87.66 per Bbl of oil and $6.49 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 December 31, 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 Reserves(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)
    9,034       28,923       13,855     $ 543,461     $ 311,447  
Underlying properties (attributable to the net profits interest)(4)
    5,110       18,559       8,203     $ 351,008     $ 249,763  
Net profits interest with cost reductions(5)
    3,187       11,678       5,133     $ 351,008     $ 249,763  
Amount per trust unit(6)
                    $ 25.32     $ 18.02  
 
 
(1) The net profits interest entitles the trust to receive 90% of the net proceeds from the sale of production of 9.11 MMBOE from the underlying properties, which equals 8.20 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 December 31, 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 $311.4 million and $249.8 million, respectively, as of December 31, 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.


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(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 13,863,889 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 9.11 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 8.20 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 9.11 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 10.5% 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 9.11 MMBOE from the underlying properties. The following graph does not include the impact of any such capital expenditures by Whiting.
 
(Estimated Production Graph)


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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 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, 2007 derived from the underlying properties’ audited statements of historical revenues and direct operating expenses included elsewhere in this prospectus. The historical financial information includes the results of acquisitions beginning on the following dates: Institutional Partnership Interests, June 23, 2005; Celero Energy, LP, October 4, 2005; and Howard Energy, August 15, 2006.
 
                         
    Year ended December 31,  
    2005     2006     2007  
    (dollars in thousands)  
 
Revenues:
                       
Oil sales
  $ 43,499     $ 53,232     $ 59,428  
Natural gas sales
    36,135       31,398       28,224  
                         
                         
                         
Total revenues
    79,634       84,630       87,652  
                         
                         
                         
Direct operating expenses:
                       
Lease operating
    16,181       21,913       23,733  
Production taxes
    5,602       6,006       6,262  
                         
                         
                         
Total direct operating expenses
    21,783       27,919       29,995  
                         
                         
                         
Excess of revenues over direct operating expenses
  $ 57,851     $ 56,711     $ 57,657  
                         
 
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, 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: Institutional Partnership Interests, June 23, 2005; Celero Energy, LP, October 4, 2005; and Howard Energy, August 15, 2006.
 
                         
    Year ended December 31,  
    2005     2006     2007  
 
Operating data:
                       
Net production:
                       
Oil (MBbls)
    893       946       956  
Natural gas (MMcf)
    5,082       5,057       4,441  
Total production (MBOE)
    1,740       1,789       1,696  
                         
                         
Oil (per Bbl)
  $ 48.72     $ 56.24     $ 62.17  
                         
                         
Natural gas (per Mcf)
  $ 7.11     $ 6.21     $ 6.36  
                         
                         
Drilling and development capital expenditures (in thousands)(1):
  $ 6,453     $ 10,036     $ 8,269  
 
 
(1) Whiting cannot provide any assurance that future capital expenditures will be consistent with historical levels.


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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 based on estimates and judgments, and readers of this prospectus 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 and operating 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 based on actual NYMEX oil prices for the months of January, February and March 2008 with April 2008 estimated to be the same as March 2008. Actual natural gas prices for the months of January, February, March and April 2008 are based on NYMEX natural gas prices on the third trading day before the end of the prior month. The projected financial information was also based on the hypothetical assumption that prices for oil and natural gas for each month during the eight month period from May 1, 2008 to December 31, 2008, equal 80% of the NYMEX futures prices for oil and natural gas on April 7, 2008 for such month, plus 20% of the Bloomberg consensus price forecasts on April 7, 2008 for oil and natural gas for 2008. These actual and estimated 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 with the resulting hypothetical prices shown in the table below. Because there is no Bloomberg consensus price for natural gas liquids, Whiting used a hypothetical price equal to approximately 65% of the price used in the table below for oil, which is consistent with the historical pricing realized by Whiting for natural gas liquids.
 


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    Hypothetical Prices for Oil and Natural Gas for 2008  
    Jan.(1)     Feb.(1)     March(1)     April(2)     May(3)     June(3)     July(3)     Aug.(3)     Sept.(3)     Oct.(3)     Nov.(3)     Dec.(3)  
 
Oil(4)
  $ 84.39     $ 86.81     $ 96.88     $ 96.88     $ 96.61     $ 96.18     $ 95.65     $ 95.12     $ 94.63     $ 94.16     $ 93.72     $ 93.28  
Natural Gas(5)
  $ 6.63     $ 7.51     $ 8.46     $ 9.09     $ 9.02     $ 9.09     $ 9.18     $ 9.22     $ 9.23     $ 9.29     $ 9.49     $ 9.76  
 
 
(1) The estimated prices for oil and natural gas are based on such month’s actual NYMEX oil and natural gas prices.
 
(2) The estimated price for oil is based on the prior month’s actual NYMEX oil price and the estimated price for natural gas is based on such month’s actual NYMEX natural gas price.
 
(3) The estimated prices for oil and natural gas are based on 80% of such month’s NYMEX futures prices for oil and natural gas on April 7, 2008 plus 20% of the Bloomberg consensus price forecasts for oil and natural gas on April 7, 2008.
 
(4) The estimated monthly prices are adjusted to take into account Whiting’s estimate of the basis differential, which is estimated to be $8.54 per Bbl of oil.
 
(5) The estimated monthly price is adjusted to take into account Whiting’s estimate of the basis differential, which is estimated to be $0.50 per Mcf of natural gas.
 
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 $72.30 for the year ended December 31, 2007, with the monthly closing prices ranging from $54.35 to $94.63 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 actual NYMEX prices for oil and natural gas or NYMEX futures prices for oil and natural gas on April 7, 2008 and Bloomberg consensus price forecasts on April 7, 2008 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 10.5% between 2008 and 2017. However, cash distributions to unitholders may decline at a faster rate than the rate of

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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(4)  
    (dollars in thousands, except per Bbl, Mcf
 
    and per trust unit amounts)  
 
Underlying properties sales volumes:
       
Oil and natural gas liquids (MBbls)
    853.9  
Natural gas (MMcf)
    3,779.2  
Assumed sales price:
       
Oil and natural gas liquids (per Bbl)
  $ 91.78  
Natural gas (per Mcf)
  $ 8.77  
Calculation of net proceeds:
       
Gross proceeds:
       
Oil and natural gas liquid sales
  $ 78,367  
Natural gas sales
    33,153  
         
Total
  $ 111,520  
         
Costs:
       
Lease operating expenses and property taxes
  $ 24,327  
Production taxes
    8,475  
Payments made or received by Whiting to settle hedge contracts
     
         
Total
  $ 32,802  
         
Net proceeds
  $ 78,718  
Percentage allocable to net profits interest
    90 %
         
Total cash proceeds to trust
    70,846  
Trust administrative expenses
    (1,000 )
         
Projected cash distribution on trust units before state income tax withholdings and reserve for future trust expenses
    69,846  
Reserve for future trust expenses(1)
    (100 )
State income tax withholdings(2)
    (427 )
         
Projected cash distribution on trust units
  $ 69,319  
         
Projected cash distribution per trust unit before state income tax withholdings and reserve for future trust expenses(3)
  $ 5.04  
         
Projected amount of cash distribution per trust unit before state income tax withholdings and reserve for future trust expenses that represents a return of capital(3)
  $ 3.84  
         
Projected cash distribution per trust unit(3)
  $ 5.00  
         
 
 
(1) The trustee anticipates maintaining a reserve each quarter equal to the trust’s out of pocket expenses for the next quarter.
 
(2) Represents projected withholding for the state of Montana. See “State Tax Considerations.”
 
(3) Assumes 13,863,889 trust units outstanding.
 
(4) 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. It is estimated that the first four quarterly distributions in May 2008, August 2008, November 2008 and February 2009 will include net proceeds from the sale of substantially all of production during 2008, except for December 2008 natural gas sales, which are estimated at 281,500 Mcf. Due to the time lag in receiving natural gas sales proceeds, the net proceeds from December 2008 natural gas sales will be distributed with the May 2009 distribution. 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.”


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The Offering
 
Trust units offered by Whiting 10,850,000 units
 
Trust units outstanding 13,863,889 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 9.11 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 8.20 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 the hedge contract counterparty 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


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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. If the net profits interest is not treated as a debt instrument, then a trust unitholder should be allowed to recoup its basis in the net profits interest. 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.


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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 and investors may not receive a return of their investment in the trust units.
 
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 from April 1, 2008 for oil and May 1, 2008 for natural gas through December 31, 2012.
 
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, $61.05 and $96.00 as of December 31, 2003, 2004, 2005, 2006 and 2007 respectively. 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, $5.52 and $7.10 as of December 31, 2003, 2004, 2005, 2006 and 2007 respectively.
 
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 from April 1, 2008 for oil and May 1, 2008 for natural gas through December 31, 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 the nonperformance of the counterparty 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


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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 9.11 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 9.11 MMBOE have been produced from the underlying properties and sold. The reserve report projects that 9.11 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


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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, and 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 60.9% of the underlying properties based on the pre-tax PV10% value contained in the reserve report. However, for the 39.1% 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.


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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. However, Whiting has no contractual obligation to make capital expenditures on the underlying properties in the future. 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 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. The reserve report reflects that the cumulative past production from the underlying properties through December 31, 2007, represents an aggregate depletion percentage of 93.9% of the estimated ultimate total production from the properties. As a result, the quantity of oil and natural gas produced from the underlying properties is expected to decline over time. The reserves attributable to the underlying properties declined 2.2% from December 31, 2006 to December 31, 2007, and the production attributable to the underlying properties declined 5.2% from 2006 to 2007. Based on the reserve report, production attributable to the underlying properties is expected to decline at an average year over year rate of approximately 10.5% 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 9.11 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 8.20 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


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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 the hedge contract counterparty upon settlement of the hedge contracts.
 
If production costs of the underlying properties and payments made by Whiting to the hedge contract counterparty 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 9.11 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 through December 31, 2012 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 9.11 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 8.20 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


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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. and Wachovia Capital Markets, LLC, acting as representatives 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.” Additionally, the trust has no employees and is reliant on Whiting’s employees to operate those underlying properties for which Whiting is designated as the operator. Whiting’s employees are also responsible for the operation of other oil and gas properties Whiting owns, which may require a significant portion or all of their time and resources. Whiting will have broad discretion over the timing and amount of operating expenditures and activities, including workover expenses and activities, which


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could result in higher costs being attributed to the net profits interest. The documents governing the trust generally 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 1,627,500 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.


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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. The net profits interest is a non-operating, non-possessory interest carved out of the oil and natural gas leasehold estate, but certain states 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 should create a fully conveyed and vested property interest under the applicable state’s laws, but certain states have not directly determined whether this would be the result. 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.


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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 60.9% 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 an institutional counterparty 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 the counterparty related to the hedge contracts and its obligations to the trust 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. Whiting cannot provide any assurance that its financial condition and economic performance will not deteriorate in the future. For example, Whiting’s net income in 2007 decreased to $130.6 million from $156.4 million in 2006 due to a 3% decrease in equivalent volumes sold, a 7% decrease in gas prices (net of hedging) between periods, higher lease operating expenses, production taxes, depreciation, depletion and amortization expenses, exploration and impairment and general and administrative expenses and change in Whiting’s production participation plan liability. 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 counterparty and Whiting. A default by the hedge contract counterparty or Whiting could reduce the amount of cash available for distribution to the trust unitholders.
 
In the event that the counterparty to the hedge contracts defaults on its obligations to make payments to Whiting under the hedge contracts, the cash distributions to the trust unitholders could 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. In addition, because the hedge contracts are with a single counterparty, JPMorgan Chase Bank National Association, the risk of default is concentrated with one financial institution. Whiting cannot provide any assurance that this counterparty will not become a credit risk in the future. The hedge contracts also have default terms applicable to Whiting, including customary cross default provisions. If Whiting were to default, the counterparty to the hedge contracts could terminate the hedge contracts and the cash distributions to trust unitholders could be materially reduced during periods of lower crude oil and natural gas prices.
 
Under certain circumstances, the trust provides that the trustee may be required to reconvey to Whiting a portion of the net profits interest, which may impact how quickly 9.11 MMBOE are produced from the underlying properties for purposes of the net profits interest.
 
If Whiting is notified by a person with whom Whiting is a party to a contract containing a prior reversionary interest that Whiting is required to convey any of the underlying properties to such person or cease production from any well, then Whiting may provide such conveyance with respect to such underlying property or permanently cease production from such well. Such a reversionary interest typically results from the provisions of a joint operating agreement that governs the drilling of wells on jointly owned property and


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financial arrangements for instances where all owners may not want to make the capital expenditure necessary to drill a new well. The reversionary interest is created because an owner that does not consent to capital expenditures will not have to pay its share of the capital expenditure, but instead will relinquish its share of proceeds from the well until the consenting owners receive payout (or a multiple of payout) of their capital expenditures. In such case, Whiting may request the trustee to reconvey to Whiting the net profits interest with respect to any such underlying property or well. The trust will not receive any consideration for such reconveyance of a portion of the net profits interest. Such reconveyance of a portion of the net profits interest may extend the time it takes for 9.11 MMBOE (which is equivalent to 8.20 MMBOE attributable to the net profits interest) to be produced from the underlying properties for purposes of the net profits interest.


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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.


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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 13,863,889 trust units, which will be distributed as a dividend to Whiting Petroleum Corporation. Whiting will pay underwriting discounts and estimated expenses of approximately $17.0 million, assuming the underwriters do not exercise their overallotment option, associated with this offering and will receive all net proceeds from the offering. The estimated net proceeds to Whiting will be approximately $200.0 million, assuming an offering price of $20.00 per trust unit (the midpoint of the range set forth on the cover page of this prospectus), and will increase to approximately $230.3 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 6.1% as of December 31, 2007 and mature in August 2010.


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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 13,863,889 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 May 30, 2008 to trust unitholders owning trust units on May 20, 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 January 1, 2008 through March 31, 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 April 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 June 30, 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 general and administrative expenses of the trust are expected to be approximately $1,000,000 in 2008 and $900,000 annually thereafter, including the administrative services fee payable to Whiting.
 
The net profits interest will terminate at the time when 9.11 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 8.20 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.
 
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.


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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 9.11 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 8.20 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.
 
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 based on estimates and judgments, and readers of this prospectus 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 and operating expenses, based on:
 
  •  the oil, natural gas and natural gas liquid production estimates contained in the reserve report; and


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  •  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 based on actual NYMEX oil prices for the months of January, February and March 2008 with April 2008 estimated to be the same as March 2008. Actual natural gas prices for the months of January, February, March and April 2008 are based on NYMEX natural gas prices on the third trading day before the end of the prior month. The projected financial information was also based on the hypothetical assumption that prices for oil and natural gas for each month during the eight month period from May 1, 2008 to December 31, 2008, equal 80% of the NYMEX futures prices for oil and natural gas on April 7, 2008 for such month, plus 20% of the Bloomberg consensus price forecasts on April 7, 2008 for oil and natural gas for 2008. These actual and estimated 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 with the resulting hypothetical prices shown in the table below. Because there is no Bloomberg consensus price for natural gas liquids, Whiting used a hypothetical price equal to approximately 65% of the price used in the table below for oil, which is consistent with the historical pricing realized by Whiting for natural gas liquids.
 
                                                                                                 
    Hypothetical Prices for Oil and Natural Gas for 2008  
    Jan.(1)     Feb.(1)     March(1)     April(2)     May(3)     June(3)     July(3)     Aug.(3)     Sept.(3)     Oct.(3)     Nov.(3)     Dec.(3)  
 
Oil(4)
  $ 84.39     $ 86.81     $ 96.88     $ 96.88     $ 96.61     $ 96.18     $ 95.65     $ 95.12     $ 94.63     $ 94.16     $ 93.72     $ 93.28  
Natural Gas(5)
  $ 6.63     $ 7.51     $ 8.46     $ 9.09     $ 9.02     $ 9.09     $ 9.18     $ 9.22     $ 9.23     $ 9.29     $ 9.49     $ 9.76  
 
 
(1) The estimated prices for oil and natural gas are based on such month’s actual NYMEX oil and natural gas prices.
 
(2) The estimated price for oil is based on the prior month’s actual NYMEX oil price and the estimated price for natural gas is based on such month’s actual NYMEX natural gas price.
 
(3) The estimated prices for oil and natural gas are based on 80% of such month’s NYMEX futures prices for oil and natural gas on April 7, 2008 plus 20% of the Bloomberg consensus price forecasts for oil and natural gas on April 7, 2008.
 
(4) The estimated monthly prices are adjusted to take into account Whiting’s estimate of the basis differential, which is estimated to be $8.54 per Bbl of oil.
 
(5) The estimated monthly price is adjusted to take into account Whiting’s estimate of the basis differential, which is estimated to be $0.50 per Mcf of natural gas.
 
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 $72.30 for the year ended December 31, 2007, with the monthly closing prices ranging from $54.35 to $94.63 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 actual NYMEX prices for oil and natural gas or NYMEX futures prices for oil and natural gas on April 7, 2008 and Bloomberg consensus price forecasts on April 7, 2008 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


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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 10.5% 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.”


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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)
    223.6       216.3       210.1       203.9       853.9  
Natural gas (MMcf)
    1,045.6       968.8       906.7       858.1       3,779.2  
Assumed sales price:
                                       
Oil and natural gas liquids (per Bbl)
  $ 87.43     $ 94.64     $ 93.28     $ 91.95     $ 91.78  
Natural gas (per Mcf)
  $ 7.52     $ 9.07     $ 9.21     $ 9.51     $ 8.77  
Calculation of net proceeds:
                                       
Gross proceeds:
                                       
Oil and natural gas liquid sales
  $ 19,549     $ 20,470     $ 19,599     $ 18,749     $ 78,367  
Natural gas sales
    7,858       8,786       8,351       8,158       33,153  
                                         
Total
  $ 27,407     $ 29,256     $ 27,950     $ 26,907     $ 111,520  
                                         
Costs
                                       
Lease operating expenses and property taxes
  $ 6,155     $ 6,118     $ 6,061     $ 5,993     $ 24,327  
Production taxes
    2,083       2,224       2,124       2,044       8,475  
Payments made or received by Whiting to settle hedge contracts
                             
                                         
Total
  $ 8,238     $ 8,342     $ 8,185     $ 8,037     $ 32,802  
                                         
Net proceeds
  $ 19,169     $ 20,914     $ 19,765     $ 18,870     $ 78,718  
Percentage allocable to net profits interest
    90 %     90 %     90 %     90 %     90 %
                                         
Total cash proceeds to trust
    17,252       18,822       17,789       16,983       70,846  
Trust administrative expenses
    (100 )     (150 )     (150 )     (600 )     (1,000 )
                                         
Projected cash distribution on trust units before state income tax withholdings and reserve for future trust expenses
    17,152       18,672       17,639       16,383       69,846  
Reserve for future trust expenses(2)
    (150 )           (600 )     650       (100 )
State income tax withholdings(3)
    (104 )     (113 )     (108 )     (102 )     (427 )
                                         
Projected cash distribution on trust units
  $ 16,898     $ 18,559     $ 16,931     $ 16,931     $ 69,319  
                                         
Projected cash distribution per trust unit before state income tax withholdings and reserve for future trust expenses(4)
  $ 1.24     $ 1.35     $ 1.27     $ 1.18     $ 5.04  
                                         
Projected amount of cash distribution per trust unit before state income tax withholdings and reserve for future trust expenses that represents a return of capital(4)
  $ 1.24     $ 0.92     $ 0.87     $ 0.81     $ 3.84  
                                         
Projected cash distribution per trust unit(4)
  $ 1.22     $ 1.34     $ 1.22     $ 1.22     $ 5.00  
                                         
 
 
(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. It is estimated that the first four quarterly distributions in May 2008, August 2008, November 2008 and February 2009 will include net proceeds from the sale of substantially all of production during 2008, except for December 2008 natural gas sales, which are estimated at 281,500 Mcf. Due to the time lag in receiving natural gas sales proceeds, the net proceeds from December 2008 natural gas sales will be distributed with the May 2009 distribution. For more information about the hypothetical assumptions made in preparing the table above, see “— Significant Assumptions Used to Prepare the Projected Cash Distributions” below.


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(2) The trustee anticipates maintaining a reserve each quarter equal to the trust’s out of pocket expenses for the next quarter.
 
(3) Represents projected withholding for the state of Montana. See “State Tax Considerations.”
 
(4) Assumes 13,863,889 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 13,863,889 trust units are issued and outstanding after the closing of the offering made hereby; (2) various realizations of production levels estimated in the reserve report; (3) the hypothetical commodity prices based upon the actual NYMEX prices for oil and natural gas or NYMEX futures prices for oil and natural gas on April 7, 2008 and Bloomberg consensus price forecasts for oil and natural gas on April 7, 2008; (4) the impact of the hedge contracts entered into by Whiting that relate to production from the underlying properties; and (5) 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 April 1, 2008 for oil and May 1, 2008 for natural gas through December 31, 2012. These hedge contracts are costless collar arrangements that hedge approximately 80% of the anticipated production attributable to the underlying properties. The crude oil hedge contracts are priced with floors ranging from $74.00 to $82.00 and ceilings ranging from $128.30 to $146.62 per Bbl of oil, and the natural gas hedge contracts are priced with floors ranging from $6.00 to $7.00 and ceilings ranging from $12.45 to $22.50 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.


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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 Oil
and Natural Gas Production
 
         
Percentage of 2008
  Total 2008 Projected
 
Estimated Oil and
  Cash Distributions
 
Natural Gas Production(1)
  Per Trust Unit  
 
90%
  $ 4.34  
95%
  $ 4.67  
100%
  $ 5.00  
105%
  $ 5.33  
110%
  $ 5.67  
 
 
(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 Oil
and Natural Gas Prices
 
         
Percentage of 2008
  Total 2008 Projected
 
Estimated Oil and
  Cash Distributions
 
Natural Gas Price(1)
  Per Trust Unit  
 
90%
  $ 4.34  
95%
  $ 4.67  
100%
  $ 5.00  
105%
  $ 5.33  
110%
  $ 5.67  
 
 
(1) Estimated prices are based on actual NYMEX oil prices for the months of January, February and March 2008 with April 2008 estimated to be the same as March 2008. Actual natural gas prices for the months of January, February, March and April 2008 are based on NYMEX natural gas prices on the third trading day before the end of the prior month. The estimated prices are also based on the hypothetical assumption that prices for oil and natural gas for each month during the eight month period from May 1, 2008 to December 31, 2008, equal 80% of the NYMEX futures prices for oil and natural gas on April 7, 2008 for such month, plus 20% of the Bloomberg consensus price forecasts on April 7, 2008 for oil and natural gas for 2008. These actual and estimated 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 with the resulting hypothetical prices shown in the table below.
 
                                                                                                 
    Hypothetical Prices for Oil and Natural Gas for 2008  
    Jan.(1)     Feb.(1)     March(1)     April(2)     May(3)     June(3)     July(3)     Aug.(3)     Sept.(3)     Oct.(3)     Nov.(3)     Dec.(3)  
 
Oil(4)
  $ 84.39     $ 86.81     $ 96.88     $ 96.88     $ 96.61     $ 96.18     $ 95.65     $ 95.12     $ 94.63     $ 94.16     $ 93.72     $ 93.28  
Natural Gas(5)
  $ 6.63     $ 7.51     $ 8.46     $ 9.09     $ 9.02     $ 9.09     $ 9.18     $ 9.22     $ 9.23     $ 9.29     $ 9.49     $ 9.76  


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(1) The estimated prices for oil and natural gas are based on such month’s actual NYMEX oil and natural gas prices.
 
(2) The estimated price for oil is based on the prior month’s actual NYMEX oil price and the estimated price for natural gas is based on such month’s actual NYMEX natural gas price.
 
(3) The estimated prices for oil and natural gas are based on 80% of such month’s NYMEX futures prices for oil and natural gas on April 7, 2008 plus 20% of the Bloomberg consensus price forecasts for oil and natural gas on April 7, 2008.
 
(4) The estimated monthly prices are adjusted to take into account Whiting’s estimate of the basis differential, which is estimated to be $8.54 per Bbl of oil.
 
(5) The estimated monthly price is adjusted to take into account Whiting’s estimate of the basis differential, which is estimated to be $0.50 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 March 31, 2008 will actually enter into the calculation of net proceeds to be received by the trust in the three months ended June 30, 2008.
 
Production Estimates.  Production estimates for 2008 are based on the reserve report. The reserve report assumed constant prices at December 31, 2007, based on a crude oil price of $96.00 ($87.66 field adjusted) per Bbl, a natural gas price of $7.10 ($6.49 field adjusted) per Mcf and the natural gas liquid price of $59.15 per Bbl. Production from the underlying properties for 2008 is estimated to be 805.4 MBbls of oil, 3,779.2 MMcf of natural gas and 48.5 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. 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 10.5% 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 actual NYMEX prices for oil and natural gas or NYMEX futures prices for oil and natural gas on April 7, 2008 and Bloomberg consensus price forecasts for oil and natural gas on April 7, 2008 as described in more detail above in ‘‘— Projected Cash Distributions.” 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, $8.54 per Bbl is deducted from the assumed sales price for crude oil in 2008 to reflect these differentials, which is 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 year ended December 31, 2007. 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. Assumed 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 65% of the hypothetical price used in


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the projected cash distribution table for oil, which is consistent with the historical pricing realized by Whiting for natural gas liquids.
 
In the cash distribution table, $0.50 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 year ended December 31, 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.  Whiting has entered into costless collar arrangements with respect to 476,280 Bbls of oil and 1,928,587 Mcf of natural gas expected to be produced from the underlying properties during 2008. The hedge contracts are priced with weighted average floors of $82.00 and weighted average ceilings of $133.20 per Bbl of oil, and weighted average floors of $7.00 and weighted average ceilings of $16.06 per Mcf of natural gas. The hedge contracts are assumed to not have any impact on the projected cash proceeds because the floors are under and the ceilings are above the hypothetical oil and natural gas prices assumed in the projected cash distribution table.
 
Costs.  For 2008, Whiting estimates lease operating expenses and property taxes to be $24.3 million, which is 7% higher than estimated in the reserve report due to expected higher energy costs, and production taxes to be $8.5 million. For the year ended December 31, 2007, lease operating expenses were $23.7 million and production taxes were $6.3 million. For a description of production expenses, see “Computation of Net Proceeds — Net Profits Interest.”
 
Administrative Expense.  Trust administrative expense for 2008 is assumed to be $1,000,000. See “The Trust.”


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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 3,051 gross (385.8 net) producing oil and natural gas wells located in 172 fields on 215,376 gross acres in 14 states. Whiting has acquired interests in these properties through various acquisitions that have occurred during its 28 year existence. For the month ended December 31, 2007, the average daily net production from these properties was 4,643 BOE/d, which equates to 4,179 BOE/d attributable to the net profits interest. Whiting operates approximately 60.9% 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 December 31, 2007, proved reserves attributable to the underlying properties, as estimated in the reserve report, were approximately 13.85 MMBOE with a pre-tax PV10% value of $311.4 million. The net profits interest entitles the trust to receive 90% of the net proceeds from the sale of production of 9.11 MMBOE of proved reserves. The 9.11 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.
 
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 during the term of the trust, 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.
 
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 10.5% from 2008 through 2017. However, cash


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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, 2007, derived from the underlying properties’ audited statements of historical revenues and direct operating expenses included elsewhere in this prospectus. The historical financial information includes the results of acquisitions beginning on the following dates: Institutional Partnership Interests, June 23, 2005; Celero Energy, LP, October 4, 2005; and Howard Energy, August 15, 2006.
 
                         
    Year ended December 31,  
    2005     2006     2007  
    (dollars in thousands)  
 
Revenues:
                       
Oil sales
  $ 43,499     $ 53,232     $ 59,428  
Natural gas sales
    36,135       31,398       28,224  
                         
Total revenues
    79,634       84,630       87,652  
                         
Direct operating expenses:
                       
Lease operating
    16,181       21,913       23,733  
Production taxes
    5,602       6,006       6,262  
                         
Total direct operating expenses
    21,783       27,919       29,995  
                         
Excess of revenues over direct operating expenses
  $ 57,851     $ 56,711     $ 57,657  
                         
 
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, 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: Institutional Partnership Interests, June 23, 2005; Celero Energy, LP, October 4, 2005; and Howard Energy, August 15, 2006.
 
                         
    Year ended December 31,  
    2005     2006     2007  
 
Operating data:
                       
Net production:
                       
Oil (MBbls)
    893       946       956  
Natural gas (MMcf)
    5,082       5,057       4,441  
Total production (MBOE)
    1,740       1,789       1,696  
Oil (per Bbl)
  $ 48.72     $ 56.24     $ 62.17  
Natural gas (per Mcf)
  $ 7.11     $ 6.21     $ 6.36  
Drilling and development capital expenditures (in thousands)(1):
  $ 6,453     $ 10,036     $ 8,269  
 
 
(1) Whiting cannot provide any assurance that future capital expenditures will be consistent with historical levels.


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Discussion and Analysis of Historical Results of the Underlying Properties
 
Comparison of Results of the Underlying Properties for the Year Ended December 31, 2007 and 2006
 
Revenues.  Oil and natural gas sales revenue increased $3.0 million from 2006 to 2007. Sales are a function of average sales prices and volumes sold. The average price realized for oil increased 11% from 2006 to 2007, and the average price realized for natural gas increased 2% between periods. Likewise, oil sales volumes increased 1% between periods. The acquisition of Howard Energy in August of 2006 added 41 Mbbls of incremental oil production in 2007. This increase in oil production was partially offset by a decrease in 2007 oil volumes of 31 Mbbls due to normal field production decline. Gas sales volumes decreased 12% or 616 MMcf between periods. Workover projects that were performed on two wells in the Permian basin had the effect of lowering the daily production rates from these wells and resulted in production declines totaling 257 MMcf from 2006 to 2007. In addition, two non-operated wells in the Gulf Coast region experienced higher than average declines in 2007. Production on the first well decreased 100 MMcf, or 34%, from 2006 to 2007, as the well produced from a strong water-drive reservoir resulting in increased water production and reduced gas production. We expect that this well will continue on a steep decline of about 40% per year. A production decline of 65 MMcf from 2006 to 2007 on the second Gulf Coast well was due to production curtailments initiated by the operator at the field’s gas processing plant and related trunk pipeline. The remaining decrease in gas production volumes of 194 MMcf related to normal field production decline. The production decline rates for the Permian basin well and latter Gulf Coast gas well stabilized by the end of 2007, and we expect their future decline rates to range from 5% to 10% going forward. Recent production rates for these wells and their estimated future decline rates have been reflected in proved reserve estimates for the underlying properties as of December 31, 2007.
 
Lease Operating Expenses.  Lease operating expenses increased $1.8 million from 2006 to 2007. The acquisition of Howard Energy in August of 2006 and new wells drilled added $1.4 million of incremental lease operating expense in 2007. Lease operating expense as a percentage of oil and gas sales increased from 26% during 2006 to 27% during 2007, and lease operating expenses per BOE increased from $12.25 during 2006 to $13.99 during 2007. The increase of 14% on a BOE basis was caused by higher energy costs and inflation in the cost of oil field goods and services. Energy costs increased 22% between periods, and costs of oil field goods and services increased 13% 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 in the various taxing jurisdictions are fully utilized. Production taxes for 2007 and 2006 were consistent between periods at 7% of oil and gas sales.
 
Excess of Revenues Over Direct Operating Expenses.  Excess of revenues over direct operating expenses increased $0.9 million from 2006 to 2007. The reasons for this increase included an 11% increase in oil prices and a 2% increase in gas prices between periods. The increased pricing was partially offset by a 5% decrease in equivalent volumes sold and higher lease operating expense and production taxes.
 
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 from 2005 to 2006. Sales are a function of average sales prices and volumes sold. The average price realized for oil increased 15% from 2005 to 2006, while the average price realized for natural gas decreased 13% between periods. In addition, oil sales volumes increased 6% between periods. Property acquisitions during 2006 and the latter part of 2005 added 107 MBbls of oil production in 2006. The incremental production from acquired properties was partially offset by oil volume decreases of 54 MBbls due to normal field production decline. The 2006 and 2005 property acquisitions also added 622 MMcf of incremental gas production in 2006. However, such volume increases were more than offset by 2006 production declines totaling 648 MMcf. A non-operated well in the Gulf Coast region experienced steep production decline in the amount of 296 MMcf from 2005 to 2006 due to production curtailments initiated by the operator at the field’s gas processing plant and related trunk pipeline. In addition, two operated wells in the Permian basin were temporarily shut-in during 2006 in order to carryout well


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workover projects, and these shut-ins resulted in production declines of 205 MMcf from 2005 to 2006. The remaining decrease in gas production volumes of 147 MMcf was due to normal field production decline.
 
Lease Operating Expenses.  Lease operating expense increased $5.7 million from 2005 to 2006. A portion of this increase resulted from incremental costs of $2.8 million associated with new property acquisitions during 2006 and the latter part of 2005, and additional costs of $0.9 million related to wells that were completed and came on-line during 2006. 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 attributable to a high level of workover activity, higher energy costs and inflation in the cost of oil field goods and services. Workovers amounted to $1.7 million in 2006, as compared to $0.7 million of workover activity during 2005. In addition, costs of oil field goods and services increased 12% 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 in the various taxing jurisdictions are fully utilized. Production taxes for 2006 and 2005 were consistent between periods at 7% of oil and gas sales.
 
Excess of Revenues Over Direct Operating Expenses.  Excess of revenues over direct operating expenses decreased $1.1 million from 2005 to 2006. The reasons for this decrease included natural gas prices that were 13% lower in 2006, higher lease operating expenses and higher production taxes resulting from continued growth, which was partially offset by a 3% increase in total production as well as an increase in average prices for oil of 15%.
 
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 April 1, 2008 for oil and May 1, 2008 for natural gas 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 a single trading counterparty, JPMorgan Chase Bank National Association. Whiting cannot provide assurance that this trading counterparty will not become a credit risk 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 April 1, 2008 for oil and May 1, 2008 for natural gas 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  
          Weighted Average
          Weighted Average
 
    Volumes
    Price (per Bbl)     Volumes
    Price (Per Mcf)  
    (Bbls)     Floor     Ceiling     (Mcf)     Floor     Ceiling  
 
Nine/Eight Months Ending December 31, 2008
    476,280     $ 82.00     $ 133.20       1,928,587     $ 7.00     $ 16.06  
Year Ending December 31, 2009
    577,986     $ 76.00     $ 137.43       2,387,688     $ 6.50     $ 17.11  
Year Ending December 31, 2010
    521,856     $ 76.00     $ 134.98       2,047,068     $ 6.50     $ 15.06  
Year Ending December 31, 2011
    475,368     $ 74.00     $ 140.15       1,803,759     $ 6.50     $ 14.62  
Year Ending December 31, 2012
    434,262     $ 74.00     $ 141.72       1,586,787     $ 6.50     $ 14.27  


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The amounts received by Whiting from the hedge contract counterparty 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 December 31, 2007. Undeveloped acreage is not significant.
 
                 
    Gross     Net  
    (acres)  
 
Rocky Mountains
    87,091       34,525  
Mid-Continent
    67,739       30,756  
Permian Basin
    23,974       8,090  
Gulf Coast
    36,572       5,617  
                 
Total
    215,376       78,988  
                 
 
The following is a summary of the producing wells on the underlying properties as of December 31, 2007:
 
                                                 
    Operated Wells     Non-Operated Wells     Total  
    Gross     Net     Gross     Net     Gross     Net  
 
Oil
    280       178.3       2,088       82.5       2,368       260.8  
Natural gas
    89       64.6       594       60.4       683       125.0  
                                                 
Total
    369       242.9       2,682       142.9       3,051       385.8  
                                                 
 
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,  
    2005     2006     2007  
    Gross     Net     Gross     Net     Gross     Net  
 
Completed
                                                 
Oil wells
    2       0.3       18       2.1       8       0.4  
Natural gas wells
    6       2.0       12       2.2       10       2.6  
Non-productive
    0       0.0       0       0.0       0       0  
                                                 
Total
    8       2.3       30       4.3       18       3.0  
                                                 


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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,  
    2005     2006     2007  
 
Average sales prices:
                       
Oil (MBbls)
  $ 48.72     $ 56.24     $ 62.17  
Natural gas (MMcf)
  $ 7.11     $ 6.21     $ 6.36  
Lease operating expense per BOE
  $ 9.30     $ 12.25     $ 13.99  
Production taxes per BOE
  $ 3.22     $ 3.36     $ 3.69  
 
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 December 31, 2007 and the average daily net production attributable to the net profits interest for the month of December 2007.
 
                                                                 
          Proved Reserves(1)     December
 
                                  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 (62 Fields)
                                                               
Sage Creek
    WY       221       0       221       2.7 %   $ 8.0       3.2 %     77  
Bainville
    MT       162       120       182       2.2       7.7       3.1       77  
Whiskey Joe
    ND       138       68       150       1.8       7.2       2.9       48  
Palomino
    MT       151       0       150       1.8       6.9       2.7       59  
Bell
    ND       141       0       141       1.7       6.2       2.5       38  
Davis Creek
    ND       148       0       148       1.8       6.2       2.5       66  
Fryberg
    ND       185       15       188       2.3       6.2       2.5       118  
Kiehl
    WY       132       0       132       1.6       5.1       2.0       52  
Hiline
    ND       84       37       91       1.1       3.6       1.4       45  
Teddy Roosevelt
    ND       71       36       77       0.9       3.5       1.4       48  
Sherwood
    ND       93       0       93       1.1       3.0       1.2       48  
Big Dipper
    ND       72       0       72       0.9       2.9       1.2       9  
Oxbow
    MT       78       52       86       1.1       2.9       1.2       40  
Ignacio Blanco
    CO       2       807       137       1.7       2.7       1.1       96  
Other
            896       1,649       1,170       14.3       34.3       13.7       536  
                                                                 
Rocky Mountains Total
            2,574       2,784       3,038       37.0 %   $ 106.4       42.6 %     1,357  


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Table of Contents

                                                                 
          Proved Reserves(1)     December
 
                                  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)  
 
Mid-Continent (56 Fields)
                                                               
Magnolia Smackover Pool Unit
    AR       839       1,210       1,041       12.7 %   $ 32.1       12.9 %     396  
Case
    MI       171       144       195       2.4       8.8       3.5       119  
Putnam
    OK       76       1,170       271       3.3       7.2       2.9       215  
Mocane-Laverne Gas Area
    OK       10       1,667       288       3.5       5.4       2.2       111  
Stephens Smart
    AR       92       0       92       1.1       3.8       1.5       35  
Nobscot Northwest
    OK       38       1,022       208       2.6       3.3       1.3       110  
Sho-Vel-Tum
    OK       54       182       84       1.0       3.1       1.2       37  
Other
            255       4,957       1,081       13.2       24.4       9.8       575  
                                                                 
Mid-Continent Total
            1,535       10,352       3,260       39.8 %   $ 88.1       35.3 %     1,598  
Permian Basin (27 Fields)
                                                               
Iatan East Howard
    TX       242       68       253       3.1 %   $ 8.5       3.4 %     90  
Fullerton
    TX       160       36       166       2.0       6.1       2.5       52  
Patricia
    TX       117       46       125       1.5       5.9       2.4       47  
Other
            292       1,871       604       7.4       15.1       5.9       347  
                                                                 
Permian Basin Total
            811       2,021       1,148       14.0 %   $ 35.6       14.2 %     536  
Gulf Coast (27 Fields)
                                                               
Mestena Grande
    TX       14       686       129       1.6 %   $ 3.5       1.4 %     70  
Other
            176       2,716       628       7.6       16.2       6.5       618  
                                                                 
Gulf Coast Total
            190       3,402       757       9.2 %   $ 19.7       7.9 %     688  
                                                                 
Total
            5,110       18,559       8,203       100.0 %   $ 249.8       100.0 %     4,179  
                                                                 
 
 
(1) The net profits interest entitles the trust to receive 90% of the net proceeds from the sale of production of 9.11 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 13.85 MMBOE with a pre-tax PV10% value of $311.4 million, although the net profits interest will terminate when 9.11 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 December 31, 2007 of $96.00 per Bbl of oil and $7.10 per Mcf of natural gas less field transportation, quality and basis differentials of $8.34 per Bbl of oil and $0.61 per Mcf of natural gas, resulting in field adjusted prices of $87.66 per Bbl of oil and $6.49 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 December 31, 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.

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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 60.9% of these properties are operated by Whiting, and, as of December 31, 2007, these properties’ reserves were 65.2% oil and natural gas liquids and 34.8% 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.
 
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 Bighorn and Powder River Basins of Wyoming as well as the Williston Basin in North Dakota and Montana, while the second, from which natural gas is primarily produced, includes southwest Wyoming, Colorado and Utah. These properties include 62 fields of which Whiting operates wells in 32 of these fields. Average daily net production attributable to the net profits interest from these properties was 1,357 BOE/d for the month of December 2007 from 717 gross (105.8 net) 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     Interest  
 
Sage Creek
  23/0   Whiting     WY     Park   Madison, Tensleep     1,363/488       41.0 %     35.2 %
Bainville
  4/15   Whiting and Others     MT     Roosevelt   Mission Canyon,
Ratcliff, Nisku,
Winnipegosis
    5,150/1,010       14.9 %     12.2 %
Whiskey Joe
  2/4   Whiting and Others     ND     Billings   Madison     7,503/3,071       32.5 %     26.6 %
Palomino
  5/0   Whiting     MT     Roosevelt   Nisku     880/492       54.4 %     45.7 %
Bell
  1/2   Whiting and Others     ND     Stark   Tyler     324/125       60.4 %     50.6 %
Davis Creek
  8/5   Whiting and Others     ND     Billings   Fryberg (Madison)     9,134/4,277       37.2 %     30.4 %
Fryberg
  0/58   Hess Corporation
and Others
    ND     Billings   Tyler     9,225/3,427       15.6 %     13.1 %
Kiehl
  5/1   Whiting and Others     WY     Crook   Minnelusa     359/213       48.2 %     36.3 %
Hiline
  3/0   Whiting     ND     Stark   Lodgepole     1,232/548       54.8 %     46.1 %
Teddy Roosevelt
  0/22   Others     ND     Billings   Mission Canyon
(Madison)
    1,760/496       5.6 %     4.8 %
Sherwood
  10/3   Whiting and Others     ND     Renville   Sherwood (Madison)     932/425       47.2 %     40.0 %
Big Dipper
  2/0   Whiting     ND     Divide   Duperow, Red River     792/632       88.8 %     77.1 %
Oxbow
  2/1   Whiting and Others     MT     Roosevelt   Nisku, Red River     3,419/1,266       45.7 %     38.4 %
Ignacio Blanco
  0/9   BP Exploration &
Production Inc.
    CO     LaPlatta   Fruitland Coal     1,079/538       25.0 %     18.8 %


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Table of Contents

Mid-Continent Region.  The underlying properties in the Mid-Continent region are located in Arkansas, Kansas, Michigan and Oklahoma. These properties include 56 fields of which Whiting operates wells in 29 of these fields. Average daily net production attributable to the net profits interest from these properties was 1,598 BOE/d for the month of December 2007 from 443 gross (175.3 net) 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     Interest  
 
Magnolia Smackover
Pool Unit
  50/1   Whiting     AR     Columbia   Smackover     4,503/2,587       71.2 %     61.6 %
Case
  5/1   Whiting     MI     Pesque Isle   Niagaran     986/946       73.3 %     61.3 %
Putnam
  11/9   Whiting     OK     Dewey   Oswego,     5,497/2,311       39.4 %     31.8 %
        and Others               Tonkawa,                        
                        Morrow,
Red Fork,
Cottage Grove
and Atoka
                       
Mocane-Laverne Gas Area
  18/18   Whiting     OK     Beaver,   Morrow     13,458/7,499       48.1 %     38.7 %
        and Others           Harper, Ellis                            
Stephens-Smart
  4/0   Whiting     AR     Columbia   Buckrange     110/110       100.0 %     84.8 %
                        Travis Peak                        
Sho-Vel-Tum
  0/73   Keith Walker Oil     OK     Carter   Hunton,     700/195       5.2 %     3.9 %
        and Gas               Penn                        
Nobscot Northwest
  70/0   Whiting     OK     Dewey,   Oswego     5,467/2,354       53.4 %     45.3 %
                    Custer                            
 
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 27 fields of which Whiting operates wells in 10 of these fields. Average daily net production attributable to the net profits interest from these properties was 536 BOE/d for the month of December 2007 from 1,620 gross (84.3 net) 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     Interest  
 
Iatan East Howard
  0/418   CrownQuest
Operating, LLC
    TX     Howard,
Mitchell
  San Andres,
San Angelo
(Glorieta),
and Clear Fork
    3,840/322       8.4 %     7.2 %
Fullerton
  9/879   Exxon Mobil
Corporation and
Whiting
    TX     Andrews   Clear Fork     1,840/1,563       1.2 %     0.9 %
Patricia
  5/1   Whiting
and Others
    TX     Dawson   Fusselman and
Sprayberry
    1,417/ 1,337       83.3 %     67.2 %
 
Gulf Coast Region.  The underlying properties in the Gulf Coast region are located in Texas, Louisiana, Mississippi and Alabama. These properties include 27 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 688 BOE/d for the month of December 2007 from 271 gross (20.4 net) 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     Interest  
 
Mestena Grande
  0/36   Cabot Oil &
Gas Corporation
    TX     Jim Hogg   Queen City     10,691/1,334       12.4 %     9.4 %


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Table of Contents

Reserves
 
Cawley, Gillespie & Associates, Inc. estimated oil (including natural gas liquids) and natural gas reserves attributable to the underlying properties as of December 31, 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 December 31, 2007 of $96.00 per Bbl of oil and $7.10 per Mcf of natural gas less field transportation, quality and basis differentials of $8.34 per Bbl of oil and $0.61 per Mcf of natural gas, resulting in field adjusted prices of $87.66 per Bbl of oil and $6.49 per Mcf of natural gas, as well as costs for estimated future development and production expenditures to produce the proved reserves as of December 31, 2007. Because oil and natural gas prices are influenced by many factors, use of prices as of December 31, 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.
 
The following table sets forth, as of December 31, 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)
    9,034       5,110       3,187  
Natural gas (MMcf)
    28,923       18,559       11,678  
Oil equivalents (MBOE)
    13,855       8,203       5,133  
Future net revenues
  $ 543,461     $ 351,008     $ 351,008  
Discounted estimated future net revenues(5)
  $ 311,447     $ 249,763     $ 249,763  
Standardized measure(6)
  $ 311,447     $ 249,763     $ 249,763  
 
 
(1) The net profits interest entitles the trust to receive 90% of the net proceeds from the sale of production of 9.11 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.


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(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 $311.4 million and $249.8 million, respectively, as of December 31, 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, 2005
    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
    1,135       1,474       1,380  
Production
    (956 )     (4,441 )     (1,696 )
                         
Balance at December 31, 2007
    9,034       28,923       13,855  
                         
                         
                         
Proved developed reserves:
                       
Balance at December 31, 2005
    10,027       38,989       16,525  
                         
Balance at December 31, 2006
    8,849       31,546       14,107  
                         
Balance at December 31, 2007
    9,034       28,923       13,855  
                         
 
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,


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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, 2005, 2006 and 2007, Whiting plugged and abandoned 6, 0 and 5 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. During 2007, sales to Teppco Crude Oil LLC and Lion Oil Company accounted for 13% and 11%, respectively, of total oil and natural gas sales related to the underlying properties. During 2006, sales to Teppco Crude Oil LLC and Lion Oil Company accounted for 13% and 10%, respectively, of total oil and natural gas sales. During 2005, sales to Teppco Crude Oil LLC accounted for 12% of total oil and natural gas sales. Whiting believes that the loss of one or both of the 10% customers does not present a material risk because there is significant competition among purchasers of crude oil and natural gas in the areas of the underlying properties and, if Whiting were to lose one or both of their largest purchasers, several entities could purchase crude oil and natural gas produced from the underlying properties with little or no interruption to Whiting’s business.
 
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;


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  •  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 28 year existence. At the time of its acquisitions of the underlying properties, Whiting undertook a title examination of these properties.
 
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 will record the conveyance of the net profits interest in the relevant real property records of all applicable jurisdictions. Whiting believes that the delivery and recording of the conveyance should create a fully conveyed and vested property interest under the applicable state’s laws, but because there is no direct authority to this effect in some jurisdictions, this may not be the result. 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 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.


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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.


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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.


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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 December 31, 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 2008 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 a negative impact on the operations of these properties and the cash distributions to the trust unitholders.


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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 68.4% and an average net revenue interest of approximately 55.7%. For the underlying properties where Whiting is not the operator, Whiting has an average working interest of approximately 17.3% and an average net revenue interest of approximately 14.2%
 
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;


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  •  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 the counterparty 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 the hedge contract counterparty 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 9.11 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, plugging back or recompletion 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, legal, accounting and administrative functions. The fee is based on a monthly charge and Whiting’s portion averaged $4,600 per annum for 2007 per active operated well, which totaled $1.8 million for the twelve months ending December 31, 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.


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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. Whiting may make such adjustments to prior calculations of net proceeds without the consent of the trust unitholders or the trustee, but is required to provide the trustee with notice of such adjustments and supporting data.
 
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.


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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 13,863,889 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 May 30, 2008 to trust unitholders owning trust units on May 20, 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 January 1, 2008 through March 31, 2008. The second quarterly distribution is expected to be made prior to or on August 29, 2008 to trust unitholders owning trust units on August 19, 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 April 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 June 30, 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. See “Computation of Net Proceeds.”
 
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 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.
 
The beneficial interest in the trust is divided into 13,863,889 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.


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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. See “Description of Trust Units — Voting Rights of Trust Unitholders” for amendments to the trust agreement that require approval 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;
 
  •  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 release, surrender or abandonment 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 its own properties and 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 terms of such indebtedness, 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


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rights with respect to any such indebtedness 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:
 
  •  accounts payable on demand;
 
  •  interest bearing obligations of the United States government;
 
  •  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 involves the release of 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; or
 
  •  the trustee determines it is in the best interests of the trust unitholders, subject to the holders representing a majority of the outstanding trust units approving the sale.
 
In addition, if Whiting is notified by a person with whom Whiting is a party to a contract containing a prior reversionary interest that Whiting is required to convey any of the underlying properties to such person or cease production from any well, then Whiting may provide such conveyance with respect to such underlying property or permanently cease production from such well. Such a reversionary interest typically results from the provisions of a joint operating agreement that governs the drilling of wells on jointly owned property and financial arrangements for instances where all owners may not want to make the capital expenditure necessary to drill a new well. The reversionary interest is created because an owner that does not consent to capital expenditures will not have to pay its share of the capital expenditure, but instead will relinquish its share of proceeds from the well until the consenting owners receive payout (or a multiple of payout) of their capital expenditures. In such case, Whiting may request the trustee to reconvey to Whiting the net profits interest with respect to any such underlying property or well. The trust will not receive any consideration for such reconveyance of a portion of the net profits interest, but such reconveyance will not have any impact on the trust’s right to receive 90% of the net proceeds from the sale of production of 9.11 MMBOE (which is equivalent to 8.20 MMBOE attributable to the net profits interest) under the net profits interest.
 
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 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 to correct errors or to settle disputes involving the conveyance. The trustee may not agree to modifications or settle disputes involving the


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conveyance if such modifications or settlements alter the nature of the net profits interest as the right to receive a share of the net proceeds from production from the underlying properties in accordance with the conveyance or result in a variance of the investment of the trust or trust unitholders. Additionally, the trustee may supplement or amend the registration rights agreement or the administrative services agreement without the approval of trust unitholders provided that such supplement or amendment would not increase the costs or expenses of the trust or adversely affect the economic interests of the trust unitholders.
 
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, including those incurred by Whiting on behalf of the trust. These trust administrative expenses are anticipated to aggregate approximately $1,000,000 in 2008 and $900,000 per year thereafter, although such costs could be greater or less depending on future events that cannot be predicted. Included in the estimate is an annual administrative fee of $160,000 for the trustee, an annual administrative fee of $3,500 for the Delaware trustee and an annual administrative fee of $200,000 for Whiting. 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 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.


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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.
 
The Delaware trustee is under no obligation to exercise any of the powers vested in it by the trust agreement, to participate in any litigation under the trust agreement or participate in any other action other than the giving of notices which may require the Delaware trustee to incur any expenses unless the trustee, trust unitholders or Whiting has offered the Delaware trustee an indemnity against the costs that may be incurred in such action by the Delaware trustee.
 
Termination of the Trust; Sale of the Net Profits Interest
 
The net profits interest will terminate at the time when 9.11 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 8.20 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. The trust will dissolve prior to the termination of the net profits interest if:
 
  •  the trust sells the net profits interest;
 
  •  annual cash proceeds to the trust 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. The trust agreement provides that where trust unitholders bring a lawsuit against the trustee to compel the trustee to bring an action against Whiting, the arbitrators may conclude that the trust unitholders are required to pay the expenses of arbitration.
 
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.


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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 13,863,889 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 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. The trustee anticipates maintaining a reserve each quarter equal to the trust’s estimated out of pocket expenses for the next quarter. 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.


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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. In determining whether the holders of the required number of units have approved any matter that is submitted to a vote of unitholders those units owned by Whiting will be disregarded if such matter either would result in increased costs and expenses to the trust or would adversely affect the economic interests of trust unitholders. 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;
 
  •  approve the sale of assets of the trust unless the sale involves the release of less than or equal to 0.25% of the total production from the underlying properties for the last twelve months and the aggregate asset sales do not have a fair market value in excess of $500,000 for the last twelve months; or
 
  •  agree to amend or terminate the conveyance.
 
In addition, certain amendments to the trust agreement, conveyance, administrative services agreement and registration rights 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” and “Description of the Trust Agreement — Duties and Powers of the Trustee.” 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.


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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 13,863,889 trust units. All of the 10,850,000 trust units sold in this offering, or the 12,477,500 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 3,013,889 trust units, or 1,386,389 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. and Wachovia Capital Markets, LLC, subject to specified exceptions. See “Underwriting” for a description of these lock-up arrangements. Upon the expiration of these lock-up agreements, 3,013,889 trust units, or 1,386,389 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 this offering, a person or persons whose trust units are aggregated that are an affiliate of the trust, who owns trust units within the definition of “restricted securities” under Rule 144 that were purchased from the trust, or any affiliate, at least six months previously, would be entitled to sell within any three-month period a number of shares that does not exceed the greater of 1% of the then outstanding trust units or the average weekly trading volume of the trust units on the New York Stock Exchange during the four calendar weeks preceding the filing of a notice of the sale on Form 144. Sales under Rule 144 by affiliates are also subject to manner of sale provisions, notice requirements and the availability of current public information about the trust.
 
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 owns trust units within the definition of “restricted securities” under Rule 144 that were purchased from the trust, or any affiliate, at least six months previously, would, beginning 90 days after this offering, be entitled to sell trust units under Rule 144 without regard to the volume limitations, manner of sale provisions or notice requirements described above and, after one year, without regard to the public information requirement.
 
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


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  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;” or
 
  •  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.
 
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.


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DIRECTORS, EXECUTIVE OFFICERS AND EXECUTIVE COMPENSATION
 
The business and affairs of the trust will be managed by the trustee. As such, the trust does not have any executive officers, directors or employees. Information relating to Whiting’s directors and compensation of Whiting’s executive officers and directors is incorporated by reference into this prospectus from its proxy statement for its 2008 annual meeting of stockholders. Information relating to Whiting’s executive officers is incorporated by reference into this prospectus from its Annual Report on Form 10-K for the year ended December 31, 2007. See “Where You Can Find More Information” for information relating to where you can find these documents.


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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.


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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


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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.
 
Reporting Requirements for Widely-Held Fixed Investment Trusts
 
Under Treasury Regulations, the trust is classified as a widely-held fixed investment trust. Those Treasury Regulations require the sharing of tax information among trustees and intermediaries that hold a trust interest on behalf of or for the account of a beneficial owner or any representative or agent of a trust interest holder of fixed investment trusts that are classified as widely-held fixed investment trusts. These reporting requirements provide for the dissemination of trust tax information by the trustee to intermediaries who are ultimately responsible for reporting the investor-specific information through Form 1099 to the investors and the IRS. Every trustee or intermediary that is required to file a Form 1099 for a trust unitholder must furnish a written tax information statement that is in support of the amounts as reported on the applicable Form 1099 to the trust unitholder. Any generic tax information provided by the trustee of the trust is intended to be used only to assist trust unitholders in the preparation of their federal and state income tax returns.
 
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, in the opinion of Foley & Lardner LLP, 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, because the net profits interest should meet the two requirements contained in Section 636 of the Code. Those requirements are that (1) but for the effect of Section 636 of the Code, the interest is an economic interest in minerals in place, and (2) the interest is at the time of its creation expected to have a life that is less than substantially all of the economic life of the minerals that the interest burdens. 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.
 
Foley & Lardner LLP is unable to render a stronger opinion regarding the treatment of the net profits interest because of uncertainty regarding the impact of payments under the hedge contracts and payments based on the production of minerals prior to the effective time of the trust on the characterization of the net profits interest for federal income tax purposes. Specifically, the legal authorities are not clear on whether any of these payments would cause the net profits interest to fail to qualify as an economic interest in minerals in place. If the net profits interest failed to so qualify, it would not be treated as a production payment under Section 636 of the Code. If the net profits interest is not properly treated as a production payment, it does not have sufficient characteristics of a traditional debt instrument to permit Foley & Lardner LLP to provide an opinion that the net profits interest will be a debt instrument for federal income tax purposes.
 
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


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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.


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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.
 
If the net profits interest is not properly treated as a debt instrument, then the U.S. federal income tax consequences are uncertain. In that event a trust unitholder should be allowed to recoup its basis in the net profits interest, either through cost depletion or amortization deductions or by excluding from income a portion of the payments received as a recovery of capital. If the basis is recovered through deductions, however, the IRS may contend that the deductions so allowed are itemized deductions and therefore subject to a 2% floor on miscellaneous itemized deductions and a phase out of excess itemized deductions. Although not certain, Foley & Lardner LLP believes that if the net profits interest was classified as other than a debt instrument, then deductions in respect of basis recovery should not be itemized deductions because under Section 62(a)(4) of the Code the deductions should be considered attributable to property held for the production of royalty income. Investors should consult their own tax advisors with regard to the consequences if the net profits interest is not properly treated as a debt instrument for federal income tax purposes.
 
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. The amount realized will be reduced by the unused net negative adjustments described above. 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 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


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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.


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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.


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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.


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STATE TAX CONSIDERATIONS
 
The following considerations are intended as a general summary of certain information regarding state income taxes and other state tax matters affecting individuals who are trust unitholders. Foley & Lardner LLP has not rendered an opinion on the state tax consequences of an investment in trust units. The trust and Whiting are not providing any tax advice with respect to the state tax consequences applicable to any particular purchaser of trust units. Accordingly, each prospective unitholder is urged to consult and depend on 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 states 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.
 
Under the laws of each state for state income tax purposes, the trust should be treated as a grantor trust, and a trust unitholder should be considered to own and receive his or her share of the trust’s assets and income.
 
Income Subject to State Tax
 
Neither Texas nor Wyoming has a state income tax applicable to individuals.
 
An individual who is a resident of North Dakota, Oklahoma, Arkansas, Montana Michigan, New Mexico, Alabama, Louisiana, Colorado, Kansas, Utah, or Mississippi, will generally be subject to income tax in his or her state of residence on that individual’s entire share of the trust’s income.
 
An individual who is a nonresident of Oklahoma, Alabama, Kansas and Utah generally will not be subject to income tax by such states 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 states. In general, an individual trust unitholder will not be deemed to carry on a trade, business, profession or occupation in such states 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 nonresident of Arkansas and Mississippi will generally be subject to income tax in those states on the individual’s share of the trust’s income attributable to such state.
 
The state income tax treatment of an individual who is a nonresident of North Dakota, Montana, Michigan, New Mexico, Louisiana and Colorado is uncertain. Nonresidents may be required to file tax returns in each of those states and/or pay taxes in each of those states on the individual’s share of the trust’s income attributable to those states.
 
Treatment as a Debt Instrument
 
For Oklahoma, Montana, New Mexico, Alabama, Colorado, Kansas and Utah, the net profits interest should be treated as a debt instrument.
 
For North Dakota, Arkansas, Michigan, Louisiana and Mississippi, it is uncertain whether the net profits interest should be treated as a debt instrument or as a mineral interest.
 
Withholding on Income
 
For North Dakota, Oklahoma, Arkansas, Michigan, New Mexico, Alabama, Louisiana, Colorado, Kansas, Utah and Mississippi, neither the trust nor Whiting should be required to withhold the income tax due 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.
 
For Montana, Whiting must withhold from the net profits interest payable to the trust, an amount equal to 6% of the value of the net amount payable to the trust from the production of oil and gas in Montana.


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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.


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SELLING TRUST UNITHOLDER
 
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 13,863,889 units, which will be distributed as a dividend to Whiting Petroleum Corporation. Of those trust units, 10,850,000 are being offered hereby and 1,627,500 will be subject to purchase by the underwriters pursuant to the underwriters’ option to purchase additional trust units. Whiting may from time to time sell any trust units it has retained. Whiting has agreed, however, not to sell any of such trust units for a period of 180 days after the date of this prospectus without the consent of Raymond James & Associates, Inc. and Wachovia Capital Markets, LLC, acting as representatives of the several underwriters. See “Underwriting.”
 
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
    13,863,889       100.0 %     10,850,000       3,013,889       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.


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UNDERWRITING
 
Subject to the terms and conditions in an underwriting agreement dated          , 2008, the underwriters named below, for whom Raymond James & Associates, Inc. and Wachovia Capital Markets, LLC are acting as representatives, 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.
                
Wachovia Capital Markets, LLC
       
RBC Capital Markets Corporation
       
Oppenheimer & Co. Inc. 
       
Stifel, Nicolaus & Company, Incorporated
       
         
Total
    10,850,000  
 
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 1,627,500 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.


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The other expenses of this offering that are payable by Whiting are estimated to be $1.8 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. and Wachovia Capital Markets, LLC. 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. and Wachovia Capital Markets, LLC may, in their discretion and at any time without notice, release all or any portion of the securities subject to these agreements. Raymond James & Associates, Inc. and Wachovia Capital Markets, LLC do 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


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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. Additionally, an affiliate of Wachovia Capital Markets, LLC is a co-syndication agent and lender under Whiting’s credit agreement and a portion of the proceeds of this offering will be used to repay debt outstanding to this affiliate of Wachovia Capital Markets, LLC under Whiting’s credit agreement. Please read “Use of Proceeds.”
 
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
 
The trust units have been approved for listing on the New York Stock Exchange under the symbol “WHX,” subject to official notice of issuance. In connection with the listing of the trust units on the New York Stock Exchange, the underwriters will undertake to sell round lots of 100 units or more to a minimum of 400 beneficial owners.


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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.


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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, 2007, 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 December 31, 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 the related financial statement schedule, incorporated in this prospectus by reference from Whiting’s Annual Report on Form 10-K for the year ended December 31, 2007, and the effectiveness of Whiting Petroleum Corporation’s internal control over financial reporting have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports, which are incorporated herein by reference. Such financial statements and financial statement schedule have been so incorporated in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.
 
Certain information appearing in this prospectus regarding the December 31, 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 report of Cawley Gillespie & Associates, Inc., independent petroleum engineers, 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, 2007 on the authority of said firm as experts in petroleum engineering.


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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, 2007; and
 
  •  Whiting’s Current Reports on Form 8-K, dated January 14, 2008 and February 21, 2008.
 
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.


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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.
 
GAAP — Generally accepted accounting principles in the United States.
 
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.


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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,


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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.