S-1/A

As filed with the Securities and Exchange Commission on March 2, 2012

Registration No. 333-178586

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Amendment No. 2 to FORM S-1 WHITING USA TRUST II (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) 1311 (Primary Standard Industrial Classification Code No.) 38-7012326 (I.R.S. Employer
Identification No.) 919 Congress Avenue, Suite 500 Austin, Texas 78701 (512) 236-6599
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices) Michael J. Ulrich The Bank of New York Mellon Trust Company, N.A., Trustee 919 Congress Avenue, Suite 500 Austin, Texas 78701 (512) 236-6599 (Name, address, including zip code, and telephone number,
including area code, of agent for service) Amendment No. 2 to FORM S-3 WHITING PETROLEUM CORPORATION (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of
incorporation or organization) 1311 (Primary Standard Industrial Classification Code No.) 20-0098515 (I.R.S. Employer
Identification No.) 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) James J. Volker Chairman 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)

with copies to:

David P. Oelman, Esq. Kathryn S. Wilson, Esq. Vinson & Elkins L.L.P. 1001 Fannin Street, Suite 2500 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.  ¨

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.  ¨

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.  ¨

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.  ¨

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.  ¨

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.  ¨

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.  ¨

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 II

Large accelerated filer  ¨	Accelerated filer  ¨	Non-accelerated filer  x	Smaller reporting company  ¨
		(Do not check if a smaller reporting company)

Whiting Petroleum Corporation

Large accelerated filer  x	Accelerated filer  ¨	Non-accelerated filer  ¨	Smaller reporting company  ¨
		(Do not check if a smaller reporting company)

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Amount to be Registered	Proposed Maximum Offering Price Per Unit(1)	Proposed Maximum Aggregate Offering Price(2)(3)	Amount of Registration Fee(4)
Units of Beneficial Interest in Whiting USA Trust II	18,400,000	$21.00	$386,400,000	$44,282

(1) Represents a bona fide estimate of the maximum aggregate offering price solely for the purpose of calculating the registration fee under Rule 457(a) under the Securities Act.

(2) Includes trust units issuable upon exercise of the underwriters’ over-allotment option.

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

(4) The total registration fee includes $44,121 that was previously paid for the registration of $385,000,000 of proposed maximum aggregate offering price of trust units in the filing of the Registration Statement on December 16, 2011.

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

The information in this preliminary prospectus is not complete and may be changed. Whiting 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 March 2, 2012

PRELIMINARY PROSPECTUS

Whiting USA Trust II

16,000,000 Trust Units

This is an initial public offering of units of beneficial interest in Whiting USA Trust II. Whiting Petroleum Corporation has formed the trust and, immediately prior to the closing of this offering, will contribute a term net profits interest in oil and natural gas properties to the trust in exchange for 18,400,000 trust units. 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 “WHZ,” subject to official notice of issuance.

The trust units.    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.

The trust.    The trust will own the net profits interest, which represents the right to receive 90% of the net proceeds from the sale of production from oil and gas properties located in the Rocky Mountains, Permian Basin, Gulf Coast and Mid-Continent regions of the United States held by Whiting. The net profits interest will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from such underlying properties and sold (which is the equivalent to 10.61 MMBOE attributable to the net profits interest), and the trust will soon thereafter wind up its affairs and terminate.

The trust unitholders.    As a trust unitholder, you will receive quarterly distributions of cash from the proceeds that the trust receives from Whiting pursuant to the net profits interest. The trust’s ability to pay such quarterly cash distributions will depend on its receipt of net proceeds attributable to the net profits interest, which will depend upon, among other things, production quantities, sale prices of oil, natural gas and natural gas liquids, costs to produce and develop the oil, natural gas and natural gas liquids and the amount and timing of trust administrative expenses.

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

These risks include the following:

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

• Estimates of future cash distributions to unitholders are based on assumptions that are inherently subjective.

• 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 processes of drilling and completing wells are high risk activities.

• 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 the underlying properties that Whiting does not operate, which could reduce production from the underlying properties, increase capital expenditures and reduce cash available for distribution to trust unitholders.

• 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 costs and expenses related to the underlying properties and other costs and expenses incurred by the trust.

• 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 and, in addition, over time will decline to zero at termination of the trust.

• 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, or that the net profits interest is not properly treated as a production payment (and thus could fail to qualify as a debt instrument) for federal income tax purposes, the trust unitholders may receive different and potentially 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(1)	$	$
Proceeds, before expenses, to Whiting(1)	$	$

(1) Excludes a structuring fee equal to 0.50% of the gross proceeds of this offering, or approximately $         million, payable to Raymond James & Associates, Inc. for evaluation, analysis and structuring of the trust. Please read “Underwriting” beginning on page 101 of this prospectus.

The underwriters may also exercise their option to purchase from Whiting up to 2,400,000 additional trust units to cover over-allotments, if any, at the initial public offering price, less the underwriting discounts, within 30 days of the date of this prospectus.

The underwriters are offering the trust units as set forth under “Underwriting” beginning on page 101 of this prospectus. Delivery of the trust units will be made on or about                     , 2012.

RAYMOND JAMES	MORGAN STANLEY
J.P. MORGAN BAIRD OPPENHEIMER & CO. RBC CAPITAL MARKETS STIFEL NICOLAUS WEISEL MORGAN KEEGAN WUNDERLICH SECURITIES

The date of this prospectus is                     , 2012

TABLE OF CONTENTS

	Page
PROSPECTUS SUMMARY		1
RISK FACTORS		18
FORWARD-LOOKING STATEMENTS		33
USE OF PROCEEDS		34
WHITING PETROLEUM CORPORATION		35
THE TRUST		37
PROJECTED CASH DISTRIBUTIONS		38
THE UNDERLYING PROPERTIES		48
COMPUTATION OF NET PROCEEDS		73
DESCRIPTION OF THE TRUST AGREEMENT		76
DESCRIPTION OF THE TRUST UNITS		82
TRUST UNITS ELIGIBLE FOR FUTURE SALE		85
DIRECTORS, EXECUTIVE OFFICERS AND EXECUTIVE COMPENSATION		87
U.S. FEDERAL INCOME TAX CONSEQUENCES		88
STATE TAX CONSIDERATIONS		97
ERISA CONSIDERATIONS		99
SELLING TRUST UNITHOLDER		100
UNDERWRITING		101
LEGAL MATTERS		105
EXPERTS		105
WHERE YOU CAN FIND MORE INFORMATION		106
GLOSSARY OF CERTAIN DEFINITIONS		107
INDEX TO FINANCIAL STATEMENTS		F-1
APPENDIX A — SUMMARY RESERVE REPORT		A-1

You should rely only on the information contained in this prospectus or in any free writing prospectus that the trust may authorize to deliver to you. Until                     , 2012 (25 days after the date of this prospectus), federal securities laws may require all dealers that effect transactions in the trust units, whether or not participating in this offering, to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

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 is not, Whiting is 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.

CONVENTIONS USED IN THIS PROSPECTUS

This prospectus has been prepared using a number of conventions, which you should consider when reading the information contained herein. Unless the context suggests otherwise, references to:

• the “trust” are to Whiting USA Trust II;

• “Whiting” are to Whiting Petroleum Corporation and its wholly owned subsidiary, Whiting Oil and Gas Corporation;

• the “net profits interest” are to the term net profits interest to be conveyed to the trust that represents the right to receive 90% of the net proceeds (as calculated as described in “Computation of net proceeds” beginning on page 73) from Whiting’s interests in the underlying properties;

• the “underlying properties” are to Whiting’s net interests in the oil and natural gas properties to which the net profits interest applies, as described in more detail in “The underlying properties” beginning on page 48;

• the “terminal production amount” are to the 11.79 MMBOE of production that is to be produced and sold (which is the equivalent of 10.61 MMBOE in respect of the trust’s right to receive 90% of the net proceeds from such reserves pursuant to the net profits interest) prior to the termination of the net profits interest (unless earlier terminated as described in “Description of the trust agreement — Termination of the trust; sale of the net profits interest” beginning on page 80);

• the “reserve report” are to the reserve report prepared by Cawley, Gillespie & Associates, Inc., an independent reserve engineering firm, of the estimates of proved oil and natural gas reserves for the underlying properties as of December 31, 2011, of which a summary is located at the back of this prospectus as Appendix A;

• “production and development costs” are to the lease operating expenses, development costs, production and property taxes, hedge payments made by Whiting to the hedge contract counterparty upon settlements of the hedge contracts, maintenance expenses and producing overhead, as described in more detail in “Computation of net proceeds” beginning on page 73; and

• the “hedge contracts” are to the contracts to which Whiting is a party at the time of the closing of this offering that relate to the underlying properties, as described in “The underlying properties — Hedge contracts” beginning on page 52.

You will find definitions for terms relating to the oil and natural gas business in “Glossary of certain definitions” beginning on page 107.

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. Unless otherwise indicated, all information in this prospectus assumes (1) no exercise of the underwriters’ over-allotment option and (2) the termination of the net profits interest on December 31, 2021.

Whiting USA Trust II was formed in December 2011 by Whiting Petroleum Corporation to own a term net profits interest in certain long-lived, predominantly producing properties located primarily in the Rocky Mountains, Permian Basin, Gulf Coast and Mid-Continent regions of the United States. The net profits interest will entitle the trust to receive 90% of the net proceeds (calculated as described below) from Whiting’s interests in the underlying properties after the effective date of the conveyance of the net profits interest to the trust. 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 administration of the trust, to holders of its trust units during the term of the net profits interest. Please read “Computation of net proceeds” beginning on page 73. The net profits interest will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 10.61 MMBOE in respect of the trust’s right to receive 90% of the net proceeds from such reserves pursuant to the net profits interest), subject to certain specified exceptions. Please see “Description of the trust agreement — Termination of the trust; sale of the net profits interest” on page 80.

As of December 31, 2011, the estimated proved reserves attributable to the underlying properties for the full economic life of the underlying properties, as estimated in the reserve report, were 18.28 MMBOE with a pre-tax PV10% value of $408.5 million. For an explanation of pre-tax PV10% value and a comparison of pre-tax PV10% value to the standardized measure of oil and gas, please read “— Major producing areas” beginning on page 3. Based on the reserve report, the net profits interest would entitle the trust to receive net proceeds from the sale of production of an estimated 10.61 MMBOE of proved reserves during the term of the net profits interest, calculated as 90% of the proved reserves attributable to the underlying properties expected to be produced during the term of the net profits interest. Based on the reserve report, the total estimated proved reserves attributable to the net profits interest had a pre-tax PV10% value of $323.6 million as of December 31, 2011. The exact rate of production attributable to the underlying properties cannot be predicted. However, because the term of the trust continues until the later of December 31, 2021, or the time when the terminal production amount has been produced and sold, trust unitholders will have the right to participate in additional proceeds attributable to the underlying properties in excess of 10.61 MMBOE in the event such amount is produced and sold prior to December 31, 2021. As of December 31, 2011 and assuming its continued ownership of the underlying properties, the total estimated proved reserves attributable to Whiting’s remaining interest in the underlying properties at the termination of the net profits interest, as estimated in the reserve report, are expected to be 6.49 MMBOE, or approximately 35.5% of total estimated proved reserves attributable to the underlying properties.

The underlying properties include interests in 1,300 gross (390.3 net) producing wells located in 49 predominantly mature fields with established production profiles in 10 states. As of December 31, 2011, approximately 96.4% of estimated proved reserves attributable to the underlying properties during the estimated term of the net profits interest were classified as proved developed producing reserves, 2.3% were classified as proved developed non-producing reserves and 1.3% were classified as proved undeveloped reserves. For the three months ended December 31, 2011, the average daily net production from the underlying properties was approximately 4,988 BOE/d (or 4,489 BOE/d attributable to the net profits interest) and was comprised of approximately 72% oil, 25% natural gas and 3% natural gas liquids. Based on the reserve report, production attributable to the underlying properties is expected to decline at an average year-over-year rate of approximately 8.4% between 2012 and 2021, assuming no additional development drilling or other development expenditures are made on the underlying properties after 2014. Whiting operates approximately 59% and 56% of the estimated proved reserve volumes and pre-tax PV10% value, respectively, of these properties based on the reserve report.

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Whiting believes that its retained interest in the underlying properties, which entitles it to 10% of the net proceeds from the sale of production attributable to the underlying properties during the term of the net profits interest and all of the net proceeds thereafter, together with its ownership of trust units, if any, will provide incentive for it to operate (or cause to be operated) the underlying properties in an efficient and cost-effective manner. In addition, Whiting has agreed to operate the properties for which it is the operator as a reasonably prudent operator in the same manner that it would operate if these properties were not burdened by the net profits interest. Furthermore, for those properties that it is not the operator, Whiting has agreed to use commercially reasonable efforts to cause the operator to operate the property in the same manner; however, Whiting’s ability to cause other operators to take certain actions is limited. Please see “Risk factors — Whiting has limited control over activities on the underlying properties that Whiting does not operate, which could reduce production from the underlying properties, increase capital expenditures and reduce cash available for distribution to trust unitholders” beginning on page 22.

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 net profits interest. The first quarterly distribution is expected to be made on or prior to May 30, 2012 to trust unitholders owning trust units on May 20, 2012. 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, 2012 through the day prior to close of this offering plus the amount payable under the net profits interest for the period from the day of closing of the offering through March 31, 2012, less any general and administrative expenses and reserves of the trust. 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 gross proceeds from the underlying properties used to calculate the net profits interest will fluctuate and 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 to be attributed to the trust, Whiting will deduct from the gross proceeds from oil, natural gas and natural gas liquids sales all production and development costs and amounts that may be reserved for future development, maintenance or operating expenses (which reserve amounts may not exceed $2.0 million at any time), all calculated on an aggregate basis for all of these properties. The production and development costs will be reduced by hedge payments received by Whiting, if any, under the hedge contracts described below and other non-production revenue. If at any time production and development 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 50% of the anticipated oil production from the estimated proved reserves attributable to the underlying properties in the reserve report for the period from April 1, 2012 through December 31, 2014. The hedge contracts provide a fixed floor price of $80.00 and a fixed ceiling price of $122.50 for this oil production during this period. During the term of the hedge contracts, Whiting expects these contracts will reduce the oil price-related risks inherent in holding interests in oil properties, although they will also limit the potential for upside during the hedged period if oil prices increase. Trust unitholders will be exposed to fluctuations in prices of natural gas and natural gas liquids throughout the term of the trust; and after the hedge contracts terminate on December 31, 2014, trust unitholders’ exposure to fluctuations in oil prices will increase. Because the trust is intended to qualify as a grantor trust for U.S. federal income tax purposes, it is generally prohibited from varying or reinvesting its assets. Permitting Whiting to enter into additional hedge arrangements after the closing of this offering relating to production from the underlying properties could be treated as the trust constructively

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retaining the right to vary its assets. Accordingly, under the terms of the conveyance, Whiting will be prohibited from entering into hedging arrangements covering the production from the underlying properties following the completion of this offering.

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, 2011 and the average daily net production attributable to the net profits interest for three months ended December 31, 2011.

Region	Reserve Category(1)	Number of Fields		Estimated Proved Reserves as of December 31, 2011														Three Months Ended December 31, 2011 Average Daily Net Production (BOE/d)
				Oil(2) (MBbl)		Natural Gas (MMcf)		Total (MBOE) (3)(4)		% Oil		% of Total Reserves		Pre-Tax PV10% Value (3)(5) (In Millions)		% of Total Pre- Tax PV10% Value
Rocky Mountain	PD				4,312		715		4,432
	PUD				41		—		41
	Total		14		4,353		715		4,473		97.3%		42.2%	$	146.2		45.2%		1,734
Permian Basin	PD				2,807		9,855		4,450
	PUD				62		170		90
	Total		17		2,869		10,025		4,540		63.2%		42.8%		128.1		39.6%		1,991
Gulf Coast	PD				700		2,897		1,182
	PUD				—		—		—
	Total		8		700		2,897		1,182		59.2%		11.1%		35.6		11.0%		617
Mid-Continent	PD				356		345		413
	PUD				—		—		—
			10		356		345		413		86.1%		3.9%		13.7		4.2%		147
Total	PD				8,175		13,812		10,476
	PUD				103		170		132
	Total		49		8,278		13,982		10,608		78.0%		100.0%	$	323.6		100.0%		4,489

(1) PD refers to proved developed reserves and PUD refers to proved undeveloped reserves.

(2) Includes 318 MBbl of natural gas liquids in the proved developed reserve category.

(3) The amounts in the table reflect the trust’s 90% net profits interest in the reserves attributable to the underlying properties during the term of the trust. Proved reserves reflected in the table above for the net profits interest are derived from oil and natural gas prices calculated using an average of the first-day-of-the month prices for each month within the 12 months ended December 31, 2011, pursuant to current SEC and FASB guidelines, which equal $96.19 per Bbl of oil and $4.12 per MMBtu of natural gas adjusted for a field transportation, quality and basis differential of $8.94 per Bbl of oil and a premium of $1.88 per Mcf of natural gas resulting in average field adjusted prices of $87.25 per Bbl of oil (which includes the effects of natural gas liquids) and $6.00 per Mcf of natural gas. The average first-day-of-the month price for the 12 months ended December 31, 2011 applied to natural gas liquids was $69.61 per Bbl.

(4) The percentage of cumulative past production from the underlying properties through December 31, 2011 relative to (a) cumulative past production from the underlying properties through December 31, 2011 together with (b) the proved reserves attributable to the underlying properties as of December 31, 2011 from the underlying properties was 86.1%, and by region was: Rocky Mountains 85.0%, Permian Basin 89.1%, Gulf Coast 88.3% and Mid-Continent 97.5%. As of December 31, 2011, the percentage of the remaining proved reserves expected to be produced during the term of the net profits interest was 64.5% and by region basis was: Rocky Mountains 60.7%, Permian Basin 68.5%, Gulf Coast 69.1% and Mid-Continent 54.8%.

(5) Pre-tax PV10% value is 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, 2011, 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. The underlying properties are located in mature fields with established production profiles. The net profits interest excludes Whiting’s interests in the Bakken and Three Forks formations in all regions. See “The underlying properties — Major producing areas” and “The underlying properties — Capital expenditure activities,” respectively, for more detailed descriptions of the underlying properties and the anticipated development plans and capital expenditures relating thereto.

Rocky Mountains Region.    The underlying properties in the Rocky Mountains region are located in Colorado, Wyoming, North Dakota and Montana. These properties consist of 14 fields of which Whiting operates wells in five of these fields. The major fields in this region include the Rangely field (operated by Chevron Corporation and Whiting) that produces from the Weber Sand zone; the Garland field (operated by Marathon Oil Corporation) that produces from the Madison and Tensleep zones; the Cedar Hills field (operated by Continental Resources Inc. and ConocoPhillips) that produces from the Red River zone; and the Whiting-operated Torchlight field that produces from the Madison and Tensleep zones. Whiting operates approximately 18% of the Rocky Mountains region properties based on average daily net production attributable to the net profits interest of 1,734 BOE/d for the three months ended December 31, 2011 from 832 gross (109.2 net) wells. Whiting estimates that the aggregate amount of capital expenditures in the Rocky Mountains region allocated to the underlying properties will be $3.2 million (or $2.9 million attributable to the trust) for 2012 and $17.4 million in aggregate (or $15.7 million attributable to the trust) thereafter.

Permian Basin Region.    The underlying properties in the Permian Basin region are located in Texas and New Mexico. These properties consist of 17 fields of which Whiting operates wells in 12 of these fields. The major fields in this region, all of which are completely or partially operated by Whiting, include the Keystone, South field that produces from the Clear Fork, Wichita Albany and Ellenberger zones; the Martin field that produces from the Clear Fork and Wichita Albany zones; the DEB field that produces from the Wolfcamp zone; the Signal Peak field that produces from the Wolfcamp zone; and the Sable field that produces from the San Andres zone. Whiting operates approximately 86% of these properties based on average daily net production attributable to the net profits interest of 1,991 BOE/d for the three months ended December 31, 2011 from 372 gross (233.4 net) wells. Whiting estimates that the aggregate amount of capital expenditures in the Pemian Basin region allocated to the underlying properties will be $3.1 million (or $2.8 million attributable to the trust) for 2012 and $1.7 million in aggregate (or $1.5 million attributable to the trust) thereafter.

Gulf Coast Region.    The underlying properties in the Gulf Coast region are located in Texas and Mississippi. These properties consist of eight onshore fields of which Whiting operates wells in four of these fields. The major field in this region is the Lake Como field that produces from the Smackover formation and is operated by Whiting. Whiting operates approximately 91% of these properties based on average daily net production attributable to the net profits interest of 617 BOE/d for the three months ended December 31, 2011 from 50 gross (18.7 net) wells. Whiting estimates that the aggregate amount of capital expenditures in the Gulf Coast Region allocated to the underlying properties will be none for 2012 and $0.4 million in aggregate (or $0.3 million attributable to the trust) thereafter.

Mid-Continent Region.    The underlying properties in the Mid-Continent region are located in Michigan, Arkansas, Oklahoma and Texas. These properties consist of 10 fields of which Whiting operates wells in five of these fields. The major field in this region is the Wesson field that produces from the Hogg Sand zone and is operated by Whiting. Whiting operates approximately 85% of these properties based on average daily net production attributable to the net profits interest of 147 BOE/d for the three months ended December 31, 2011 from 46 gross (29.1 net) wells. Whiting estimates no capital expenditures in the Mid-Continent Region during the term of the net profits interest.

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KEY INVESTMENT CONSIDERATIONS

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

• Long-lived producing properties.    The mature oil and natural gas properties comprising the underlying properties are long-lived, predominantly producing properties with established production profiles. Based on the reserve report and assuming for purposes of this calculation that no additional development drilling or other development expenditures are made on the underlying properties after 2014, production attributable to the underlying properties is expected to decline at an average year-over-year rate of approximately 8.4% between 2012 and 2021.

• Potential upside from accelerated production.    The net profits interest will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 10.61 MMBOE in respect of the trust’s right to receive 90% of the net proceeds from such reserves pursuant to the net profits interest). In the event 11.79 MMBOE is produced and sold prior to December 31, 2021, the trust unitholders will have the right to participate in additional proceeds attributable to the net profits interest in excess of 10.61 MMBOE until December 31, 2021.

• 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. As of December 31, 2011, proved developed producing reserves represented 96.4% of the estimated proved reserves attributable to the underlying properties during the estimated term of the net profits interest.

• Strong oil pricing fundamentals.    Based on production for the three months ended December 31, 2011 attributable to the net profits interest, approximately 75% was crude oil and natural gas liquids. In its “Annual Energy Outlook 2012 Early Release Overview” (released January 23, 2012), the U.S. Energy Information Administration (“EIA”) projected that sweet crude oil prices would rise to $120.00 per Bbl in 2016. On the date of the report, the 12-month NYMEX strip oil price was $100.35 per Bbl. The projected long-term gradual rise assumes the recovery of the world economy results in higher global oil demand, that limitations on economic access to resources in many areas controlled by countries who are not members of the Organization of Petroleum Exporting Countries (“OPEC”) restrain the growth of non-OPEC oil production and that OPEC production maintains a relatively constant share of total world supply.

• Diversified well locations.    The underlying properties include interests in 1,300 gross (390.3 net) producing wells in 49 fields located in 10 states. As a result, the loss of production from any one well or geographically concentrated group of wells is not likely to have a material adverse effect on the net proceeds from the sale of production that are attributable to the trust.

• Operational control.    The right to operate an oil and natural gas lease is important because the operator can control the timing and amount of discretionary expenditures for operational and development activities. As of December 31, 2011, Whiting operated approximately 59% and 56% of the estimated proved reserves and pre-tax PV10% value of the underlying properties. Based on production for the three months ended December 31, 2011 attributable to the net profits interest, Whiting operated approximately 60% of the underlying properties.

• Downside oil price protection through December 31, 2014.    Whiting has entered into costless collar arrangements to hedge approximately 50% of the anticipated oil production from the estimated proved reserves attributable to the underlying properties for the period from April 1, 2012 through December 31, 2014. The crude oil hedge contracts are priced with floors of $80.00 and ceilings of $122.50 per Bbl of oil. Assuming production occurs as estimated by the reserve report, this would represent approximately 14.5% of the estimated proved reserves attributable to the net profits interest. The costless collars are intended to

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provide certain downside price protection while allowing cash flow to be enhanced or maintained during periods of rising commodity prices and corresponding cost increases.

• 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 28 years of experience in the oil and gas industry and its personnel have extensive operational experience in each of the core geographical areas in which the oil and natural gas properties comprising the underlying properties are located. Additionally, Whiting has sponsored one prior trust, Whiting USA Trust I (NYSE: WHX), which completed its initial public offering in 2008. For more information on Whiting and Whiting USA Trust I, see “Whiting Petroleum Corporation” on page 35.

SUMMARY OF ESTIMATED PROVED RESERVES

Summary of estimated proved reserves of underlying properties and net profits interest.    The following table sets forth, as of December 31, 2011, certain estimated proved oil (including natural gas liquids) and natural gas reserves and the estimated pre-tax PV10% value 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 SEC. A summary of the reserve report is included as Appendix A to this prospectus. Estimated proved reserves reflected in the table below for the underlying properties and the net profits interest are derived from oil and natural gas prices calculated using an average of the first-day-of-the month price for each month within the 12 months ended December 31, 2011, pursuant to current SEC and FASB guidelines, which equal $96.19 per Bbl of oil and $4.12 per MMBtu of natural gas adjusted for a field transportation, quality and basis differential of $8.94 per Bbl of oil and a premium of $1.88 per Mcf of natural gas. The resulting average field adjusted prices used to estimate the proved reserves in the table below are $87.25 per Bbl of oil (which includes the effects of natural gas liquids) and $6.00 per Mcf of natural gas. The average first-day-of-the month price for the 12 months ended December 31, 2011 applied to natural gas liquids was $69.61 per Bbl. 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 Mcf 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, 2011, 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.

	As of December 31, 2011
	Estimated Proved Reserves						Pre-Tax PV10% Value(2)
	Oil(1) (MBbl)		Natural Gas (MMcf)		Oil Equivalent (MBOE)
							(in thousands)
Underlying properties (100%)(3)		14,687		21,554		18,280	$	408,503
Underlying properties (attributable to the net profits interest)(4)		8,278		13,982		10,608	$	323,597

(1) Includes natural gas liquids.

(2) The pre-tax PV10% value of the estimated proved reserves attributable to the underlying properties and the net profits interest were determined using a discount rate of 10% per annum. As of December 31, 2011, 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 measures of the underlying properties and the underlying properties attributable to the net profits interest equal their corresponding pre-tax PV10% values, which totaled $408.5 million and $323.6 million, respectively, as of December 31, 2011.

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(3) Reflects 100% of volumes and pre-tax PV10% value of the estimated total proved reserves attributable to the underlying properties for the full economic life of the underlying properties.

(4) Reflects 90% of volumes and pre-tax PV10% value 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. Pre-tax PV10% value takes into account future estimated costs in calculating value.

Projected production attributable to the net profits interest.    The following graph shows projected production of estimated 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. 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 or if expected future development or capital expenditures are delayed, reduced or cancelled. Also, the exact rate of production cannot be predicted with certainty and such amount may decline faster than estimated in the reserve report.

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HISTORICAL RESULTS OF THE UNDERLYING PROPERTIES

The summary financial data presented below should be read in conjunction with the audited statements of historical revenues and direct operating expenses and the unaudited statements of historical revenues and direct operating expenses of the underlying properties, the related notes and “The underlying properties — Discussion and analysis of historical results of the underlying properties” beginning on page 51. 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, 2011, derived from the underlying properties’ audited and unaudited statements of historical revenues and direct operating expenses included elsewhere in this prospectus. The unaudited statements were prepared on a basis consistent with the audited statements and, in the opinion of Whiting, include all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the revenues, direct operating expenses and the excess of revenues over direct operating expenses relating to the underlying properties for the periods presented.

	Year Ended December 31,
	2009 (as restated)		2010 (as restated)		2011
	(dollars in thousands)
Revenues:
Oil sales(1)	$	85,826	$	104,667	$	120,879
Natural gas sales		19,791		19,041		16,893
Total revenues	$	105,617	$	123,708	$	137,772
Direct operating expenses:
Lease operating	$	35,076	$	37,391	$	39,377
Production taxes		5,718		6,571		7,536
Total direct operating expenses	$	40,794	$	43,962	$	46,913
Excess of revenues over direct operating expenses	$	64,823	$	79,746	$	90,859

(1) Includes natural gas liquids.

The following table provides unaudited 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, 2011. 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.

	Year Ended December 31,
	2009		2010		2011
Net sales volumes:
Oil (MBbl)(1)		1,572		1,459		1,382
Natural gas (MMcf)		4,318		3,335		2,717
Total sales volumes (MBOE)		2,292		2,015		1,834
Average realized sales prices:
Oil (per Bbl)(1)	$	54.60	$	71.74	$	87.47
Natural gas (per Mcf)	$	4.58	$	5.71	$	6.22
Capital expenditures (in thousands)	$	20,229	$	25,969	$	19,424

(1) Includes natural gas liquids.

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PRO FORMA DISTRIBUTABLE INCOME FOR THE TRUST

The summary financial data presented below should be read in conjunction with the unaudited pro forma financial statements and related notes beginning on page F-14. This pro forma data gives effect to the trust formation and the conveyance of the term net profits interest in the underlying properties to the trust by Whiting as if they occurred January 1, 2011. Whiting believes that the assumptions used provide a reasonable basis for presenting the effects directly attributable to this transaction. The summary financial data presented below is for information purposes only. It does not purport to present the results that would have actually occurred had the net profits interest conveyance been completed on the assumed date or for the period presented or which may be realized in the future.

	Year Ended December 31, 2011
	(dollars in thousands, except per unit amount)
Historical results
Income from Net Profits Interest	$	65,335
Pro Forma Adjustments
Less:
Trust general and administrative expenses		(375	)
State income tax withholdings		(94	)
Distributable income	$	64,866
Distributable income per trust unit(1)	$	3.53

(1) Pro forma per unit amount assumes the issuance of 18,400,000 trust units.

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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 liquids production for the first quarter of 2012 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 liquids production for the last quarter of 2012. For a quarterly projection of cash distributions over the same period, see “Projected cash distributions” beginning of page 38. The table also reflects the methodology for calculating the projected cash distributions. The cash distribution projections were prepared by Whiting for the twelve months ending December 31, 2012 on a cash basis based on the hypothetical assumptions that are described in “Projected cash distributions — Significant assumptions used to prepare the projected cash distributions” beginning on page 43. Actual cash distributions may vary from those presented. Neither Whiting’s independent auditors, nor any other independent accountants or other third parties, 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.

The projected cash distributions are based upon certain assumptions, including among other things, assumptions related to commodity prices. Oil prices underlying the assumed reference prices in the projected cash distributions table for the months of January and February 2012 are based on average daily WTI Cushing crude oil spot prices for each month (with the February reference price being the average daily price through February 24, 2012). For the balance of 2012, the assumed reference price for oil is the average of the settled NYMEX price for oil for the month of March and the NYMEX futures prices for oil for April through December, as reported on February 24, 2012. 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. Natural gas prices underlying the assumed reference prices in the projected cash distributions table for the months of January and February 2012 are based on actual settled NYMEX prices for natural gas. For the balance of 2012, the assumed reference price for natural gas is the average of the NYMEX futures prices for natural gas for March through December, each as reported on February 24, 2012. Published NYMEX benchmark prices for natural gas are based upon delivery at the Henry Hub in Louisiana. The assumed reference prices for natural gas liquids are equal to approximately 68% of the assumed reference price for oil for the corresponding month, which is consistent with the historical pricing realized by Whiting for its natural gas liquids. The assumed realized sales prices for oil, natural gas and natural gas liquids are adjusted to reflect differentials, which are the average differences between NYMEX published prices and the prices received by Whiting during the year ended December 31, 2011. For more information about differential assumptions, please see “Projected cash distributions — Significant assumptions used to prepare the cash distributions – Oil, natural gas and natural gas liquids prices” on page 44.

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 liquids prices. See “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 liquids prices, subject to the hedge contracts. The hedge contracts will limit the potential for increases in cash distributions due to oil price increases from April 1, 2012 through December 31, 2014” beginning on page 18 and “Projected cash distributions — Sensitivity of projected cash distributions to oil, natural gas and natural gas liquids production and prices” beginning on page 45, 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 for 2012 shown in the table below are not indicative of distributions for future years. Because payments to the trust will be generated by

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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 8.4% between 2012 and 2021, assuming no additional development drilling or other development expenditures are made on the underlying properties after 2014. 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 or if expected future development is delayed, reduced or cancelled. 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” beginning on page 22.

Projected Cash Distributions	Projection for Year Ending December 31, 2012(1)
	(dollars in thousands, except per Bbl, Mcf, MMBtu and per trust unit amounts)
Underlying properties sales volumes:
Oil and natural gas liquids (MBbl)		1,259
Natural gas (MMcf)		2,228
Assumed reference price:
Oil (per Bbl)	$	108.44
Natural gas (per MMBtu)	$	2.96
Assumed realized sales price:
Oil (per Bbl)	$	98.54
Natural gas (per Mcf)	$	4.27
Calculation of net proceeds:
Gross proceeds:
Oil and natural gas liquids sales	$	124,068
Natural gas sales		9,519
Total	$	133,587
Production and development costs:
Lease operating expenses	$	36,350
Production taxes		7,514
Development costs		6,306
Payments made (or received) by Whiting to settle hedge contracts(2)		—
Total	$	50,170
Whiting expense reserve(3)		—
Net proceeds	$	83,417
Percentage allocable to net profits interest		90	%
Total cash proceeds to trust	$	75,075
Trust administrative expenses(4)		(1,000	)
Projected cash distributions on trust units before state income tax withholdings and reserve for future trust expenses	$	74,075
Trustee reserve for future trust expenses(5)		—
State income tax withholdings(6)		(73	)
Projected cash distributions on trust units	$	74,002
Projected cash distributions per trust unit before state income tax withholdings and reserve for future trust expenses(7)	$	4.02
Projected cash distributions per trust unit(7)	$	4.02

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(1) The cash distributions projections were prepared by Whiting on a cash basis based on hypothetical assumptions. Actual cash distributions may vary from those presented. For more information about the hypothetical assumptions made in preparing the table above, including the impact of the time lag in receiving oil, natural gas and natural gas liquids sales proceeds, see “Projected cash distributions — Significant assumptions used to prepare the projected cash distributions” beginning on page 43.

(2) Production and development costs will be reduced by hedge payments and other non-production revenue received by Whiting under the hedge contracts. If the hedge payments and other non-production revenue received by Whiting under the hedge contracts exceed production and development costs during a quarterly period, the use of such excess amounts to offset costs will be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period when the current and deferred hedge payments and other non-production revenue are less than the applicable production and development costs.

(3) Whiting may reserve from the gross proceeds from sales of production amounts up to a total of $2.0 million at any time for future development, maintenance or operating expenses. However, Whiting does not anticipate funding such reserve between January 1, 2012 and December 31, 2012, but plans on deducting from the net proceeds only actual costs paid for development, maintenance and operating expenses.

(4) Total general and administrative expenses of the trust on an annualized basis for 2012 are expected to be $1.0 million, which includes an annual administrative services fee to Whiting in the amount of $200,000, the annual fee to the trustees, accounting fees, engineering fees, printing costs and other expenses properly chargeable to the trust.

(5) The trustee may reserve from the cash distribution funds to pay for future trust expenses. However, the trustee does not anticipate funding such reserve between January 1, 2012 and December 31, 2012.

(6) Represents projected withholding for the state of Montana. See “State tax considerations” beginning on page 97.

(7) Calculated based on 18,400,000 trust units outstanding.

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. As of February 29, 2012, Whiting’s market capitalization was approximately $6.9 billion and as of December 31, 2011, it had total estimated proved reserves of 345.2 MMBOE. 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.

SUMMARY OF RISK FACTORS

An investment in the trust units involves risks associated with fluctuations 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. Please read “Risk factors” beginning on page 18.

• The amounts of cash distributions by the trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquids prices, subject to the hedge contracts. The hedge contracts will limit the potential for increases in cash distributions due to oil price increases from April 1, 2012 through December 31, 2014.

• Estimates of future cash distributions to unitholders are based on assumptions that are inherently subjective.

• 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.

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• 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 processes of drilling and completing wells are high risk activities.

• The trust and the trust unitholders will have no voting or managerial rights with respect to the underlying properties. As a result, neither the trust nor the trust unitholders will have any ability to influence the operation of the underlying properties.

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

• Shortages or increases in costs of oil field equipment, services, qualified personnel and supply materials could delay production, thereby reducing the amount of cash available for distribution.

• Whiting or other operators may abandon individual wells or properties that it or they reasonably believe 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 costs, expenses and reserves related to the underlying properties and other costs and expenses incurred by the trust.

• An increase in the differential or decrease in the premium 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.

• Financial returns to purchasers of trust units will vary in part based on how quickly 11.79 MMBOE are produced from the underlying properties and sold, and it is not known when that will occur.

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

• The trust may lose value as a result of title deficiencies with respect to the underlying properties.

• 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, if any, 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 and, in addition, over time will decline to zero at termination of 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.

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• 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.

• Climate change legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for oil and gas which could reduce the amount of cash available for distribution to trust unitholders.

• Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect Whiting’s services.

• 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 or Whiting could reduce the amount of cash available for distribution to the trust unitholders.

• The financial results of the trust may differ from the financial results of Whiting USA Trust I.

• 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 the terminal production amount is produced from the underlying properties for purposes 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 (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 properly treated as a production payment (and thus could fail to qualify as a debt instrument) for federal income tax purposes, the trust unitholders may receive different and potentially less advantageous tax treatment from that described in this prospectus.

• The tax treatment of an investment in trust units could be affected by recent and potential legislative, judicial or administrative changes and differing opinions, possibly on a retroactive basis.

• Trust unitholders will be required to pay taxes on their share of the trust’s income even if they do not receive any cash distributions from the trust.

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STRUCTURE OF THE TRUST

Prior to the completion of this offering, Whiting Oil and Gas Corporation, a wholly-owned subsidiary of Whiting Petroleum Corporation, will contribute the net profits interest to the trust in exchange for 18,400,000 trust units, which it will then distribute to Whiting Petroleum Corporation as a dividend. In connection with the closing of this offering, Whiting Petroleum Corporation will sell to the public approximately 87.0% of these units in this offering, or a total of 100.0% if the underwriters’ over-allotment option is exercised in full. The following chart shows the relationship of Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, the trust and the trust unitholders immediately following the closing of this offering, assuming no exercise of the underwriters’ over-allotment option.

(1) In the event that the underwriters’ over-allotment option is exercised in full, the public trust unitholders will own 100.0% of the trust units.

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 trust are located at 919 Congress Avenue, Suite 500, Austin, Texas 78701, and its telephone number is (512) 236-6599.

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THE OFFERING

Trust units offered by Whiting 16,000,000 units, or 18,400,000 units if the underwriters’ over-allotment option is exercised in full.

Trust units outstanding 18,400,000 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 will pay all underwriting discounts, the structuring fee and the offering expenses associated with this offering. Whiting intends to use the net proceeds from this offering to repay a portion of the debt outstanding under its credit agreement. See “Use of proceeds” on page 34.

NYSE symbol WHZ

Quarterly cash distributions 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. The first distribution is expected to be made on or prior to May 30, 2012 to trust unitholders owning trust units on May 20, 2012. 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, 2012 through the day prior to close of this offering plus the amount payable under the net profits interest for the period from the day of closing of the offering through March 31, 2012, less any general and administrative expenses and reserves of the trust.

Actual cash distributions to the trust unitholders will fluctuate quarterly based upon, among other things, production quantities, sales prices of oil, natural gas and natural gas liquids, and production and development costs. 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 liquids production from proved reserves attributable to the underlying properties is expected to decline over the term of the net profits interest. See “Risk factors” beginning on page 18.

Termination of the trust The net profits interest will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 10.61 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.

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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 through deductions, amortization or otherwise. However, any deductions that may 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 “U.S. federal income tax consequences” beginning on page 88.

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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 liquids prices, subject to the hedge contracts. The hedge contracts will limit the potential for increases in cash distributions due to oil price increases from April 1, 2012 through December 31, 2014.

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 applicable to the underlying properties 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:

• changes in regional, domestic and global supply and demand for oil and natural gas;

• the actions of the Organization of Petroleum Exporting Countries;

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

• political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity, such as recent conflicts in the Middle East;

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

• the effects of global credit, financial and economic issues;

• the level of global oil and natural gas inventories;

• developments of United States energy infrastructure, such as the recent announcement of the planned reversal of the Seaway pipeline from Cushing Oklahoma to the Gulf Coast and the development of liquified natural gas exporting facilities and the perceived timing thereof;

• weather conditions;

• technological advances affecting energy consumption;

• domestic and foreign governmental regulations;

• proximity and capacity of oil and natural gas pipelines and other transportation facilities;

• the price and availability of competitors’ supplies of oil and natural gas in captive market areas;

• the price and availability of alternative fuels; and

• acts of force majeure.

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

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Recent oil prices have been high compared to historical prices. For example, the NYMEX crude oil spot prices per Bbl were $44.60, $79.36, $91.38, $98.83 and $109.77 as of December 31, 2008, 2009, 2010 and 2011 and February 24, 2012, respectively. Additionally, natural gas prices have been volatile in the recent past. The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of 2010:

	Q1 2010		Q2 2010		Q3 2010		Q4 2010		Q1 2011		Q2 2011		Q3 2011		Q4 2011
Crude Oil (per Bbl)	$	78.79	$	77.99	$	76.21	$	85.18	$	94.25	$	102.55	$	89.81	$	94.02
Natural Gas (per MMBtu)	$	5.30	$	4.09	$	4.39	$	3.81	$	4.10	$	4.32	$	4.20	$	3.54

Whiting has entered into hedge contracts, which are structured as costless collar arrangements, that will hedge approximately 50% of the anticipated oil production from the estimated proved reserves attributable to the underlying properties from April 1, 2012 through December 31, 2014. These hedge contracts, however, only cover a portion of the oil volumes and none of the natural gas or natural gas liquids volumes that are expected to be produced during such period. Whiting has not entered into any hedge contracts relating to oil, natural gas or natural gas liquids volumes expected to be produced after 2014, 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 to trust unitholders may be subject to significantly greater fluctuation after 2014 as a result of changes in oil and other commodity prices because there will be no hedge contracts in place to reduce the effects of any changes in commodity prices. Furthermore, because of the differentials between NYMEX or other benchmark prices of oil and the wellhead prices received, hedge contracts may not totally offset the effects of price fluctuations. The hedge contracts may also limit the amount of cash available for distribution if oil prices increase above specified levels. 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 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 likely materially reduce the amount of cash available for distribution to the trust unitholders.

Estimates of future cash distributions to unitholders are based on assumptions that are inherently subjective.

The projected cash distributions to trust unitholders in 2012 contained elsewhere in this prospectus are based on Whiting’s calculations, and Whiting has not received an opinion or report on such calculations from any independent accountants or other third parties. Such calculations are based on assumptions about drilling, production, crude oil and natural gas prices, hedging activities, development expenditures, expenses, and other matters that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. In particular, these estimates have assumed that crude oil and natural gas production is sold in 2012 at assumed realized prices of $98.54 per Bbl in the case of crude oil and $4.27 per Mcf in the case of natural gas. These

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prices are based in part off of assumed reference prices for oil, natural gas and natural gas liquids for 2012 that are derived from spot prices for oil and average settled NYMEX prices and NYMEX futures prices on February 24, 2012 for oil and natural gas. Alternative sources for projected futures prices for oil and natural gas, including those of affiliates of certain of the underwriters, project prices that are lower than those underlying the assumed reference prices. Accordingly, actual (and therefore realized) prices for oil, natural gas and natural gas liquids may be significantly lower. Additionally, these estimates assume the underlying properties will achieve production volumes in such amounts and at such dates as are set forth in the reserve report; however, actual production volumes may be significantly lower. If prices or production are lower than expected, the amount of cash available for distribution to trust unitholders would be reduced. Furthermore, the projections also assume that the operators of the underlying properties for which Whiting is not the operator will not increase their capital expenditures budgets for such properties from the most recently provided estimates, some of which were provided in the fourth quarter of 2011. Given the increase in the price of oil in recent months, such operators may seek to increase capital expenditures on these properties, which would result in increased costs not reflected in the reserve report. Such increased costs would likely reduce the cash available for distribution to trust unitholders during the twelve months ending December 31, 2012 and may have the potential effect of reducing the aggregate amount of cash obtained by the trust over its term.

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 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 costs, gathering and transportation costs, severance and excise taxes and capital expenditures.

Changes in these assumptions may materially alter production and reserve estimates.

The estimated proved reserves attributable to the net profits interest and the pre-tax PV10% value attributable to the net profits interest are based on estimates of reserve quantities and revenues for the underlying properties. See “The underlying properties — Reserve report” 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.

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 liquids production and prices and the costs incurred to exploit oil and natural gas reserves attributable to the underlying properties. Drilling, production or transportation accidents that temporarily or permanently halt the production and sale of oil, natural gas and natural gas liquids at any of the underlying properties will reduce trust distributions by reducing the amount of net proceeds available for distribution. For example, accidents may occur that result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any costs incurred in connection with any such accidents that are not insured against will have the effect of reducing the net proceeds available for distribution to the trust. Also, Whiting does not have insurance policies in effect that

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are intended to provide coverage for losses solely related to hydraulic fracturing operations. See “The underlying properties — Hydraulic fracturing.” In addition, curtailments or damage to pipelines used to transport oil, natural gas and natural gas liquids 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 liquids 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.

Also, drilling, production and transportation of hydrocarbons bear an inherent risk of loss of containment. Potential consequences include loss of reserves, loss of production, loss of economic value associated with the affected wellbore, contamination of soil, ground water, and surface water, as well as potential fines, penalties or damages associated with any of the foregoing consequences.

The processes of drilling and completing wells are high risk activities.

The processes of drilling and completing wells are subject to numerous risks beyond the trust’s and Whiting’s control, including risks that could delay the current drilling schedule of Whiting or any other operator of an underlying property and the risk that drilling will not result in commercially viable production. Neither Whiting nor any other operator is obligated to undertake any development activities, so any drilling and completion activities will be subject to their reasonable discretion. Further, Whiting’s or any other operator’s future business, financial condition, results of operations, liquidity or ability to finance its share of planned development expenditures could be materially and adversely affected by any factor that may curtail, delay or cancel drilling, including the following:

• delays imposed by or resulting from compliance with regulatory requirements;

• pressure or irregularities in geological formations;

• shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs, completion services and CO₂;

• equipment failures or accidents;

• adverse weather conditions, such as freezing temperatures, hurricanes and storms;

• reductions in oil, natural gas and natural gas liquids prices;

• pipeline takeaway and refining and processing capacity; and

• title problems.

In the event that development activities are delayed or cancelled, or development wells have lower than anticipated production, due to one or more of the factors above or for any other reason, estimated future distributions to unitholders may be reduced.

The trust and the trust unitholders will have no voting or managerial rights with respect to the underlying properties. As a result, neither the trust nor the trust unitholders will have any 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, including underlying properties

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where Whiting is the operator. 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 the underlying properties that Whiting does not operate, which could reduce production from the underlying properties, increase capital expenditures and reduce cash available for distribution to trust unitholders.

Whiting is currently designated as the operator of approximately 56% of the underlying properties based on the pre-tax PV10% value contained in the reserve report. However, for the 44% of the underlying properties that it 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 decisions with respect to the timing and amount of capital expenditures, the period of time over which the operator seeks to generate a return on capital expenditures, the inclusion of other participants in drilling wells, and the use of technology, as well as the operator’s expertise and financial resources and the operator’s relative interest in the underlying field. Operators may also opt to decrease operational activities following a significant decline in oil prices. 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. Accordingly, while Whiting has agreed to use commercially reasonable efforts to cause the operator to act as a reasonably prudent operator, it will be limited in its ability to do so.

Shortages or increases in costs of oil field equipment, services, qualified personnel and supply materials could delay production, thereby reducing 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. Additionally, operations on the underlying properties in some instances require supply materials such as CO₂ for production which could become subject to shortage and increasing costs. Shortages of field personnel, equipment or supply materials or price increases could significantly decrease the amount of cash available for distribution to the trust unitholders, or restrict operations on the underlying properties.

Whiting or other operators may abandon individual wells or properties that it or they reasonably believe to be uneconomic.

Whiting or other operators may abandon any well if it or they reasonably believe 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. The reserves attributable to the underlying properties are depleting assets, which means that the reserves attributable to the underlying properties will decline

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over time. The reserve report reflects that the cumulative past production from the underlying properties through December 31, 2011, represents an aggregate depletion percentage of 86.1% 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. As of December 31, 2011, the percentage of remaining reserves expected to be produced during the term of the net profits interest was 64.5%. The reserves attributable to the underlying properties declined 10.1% from December 31, 2010 to December 31, 2011, and the production attributable to the underlying properties declined 8.9% for the year ended December 31, 2011 as compared to the year ended December 31, 2010. Based on the reserve report, production attributable to the underlying properties is expected to decline at an average year-over-year rate of approximately 8.4% between 2012 and 2021, assuming the level of development drilling and development expenditures on the underlying properties disclosed elsewhere in this prospectus through 2014 and none thereafter. 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 or if expected future development is delayed, reduced or cancelled. 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 on the later to occur of (1) December 31, 2021, or (2) the time when the terminal production amount has been produced from the underlying properties and sold.

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. If the underwriters’ over-allotment option is exercised in full, Whiting will not own any trust units, which could reduce its incentive to operate the underlying properties in an efficient and cost-effective manner.

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 and will not be permitted to enter into any new hedging arrangements.

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

The amount of cash available for distribution by the trust will be reduced by the amount of any costs, expenses and reserves related to the underlying properties and other costs and expenses incurred by the trust.

The net profits interest will bear its share of all production and development costs and expenses related to the underlying properties, such as lease operating expenses, production and property taxes, development costs and hedge expenses, which will reduce the amount of cash received by the trust and thereafter distributable to trust unitholders. Additionally, amounts may be reserved by Whiting for future development, maintenance or operating expenses (which reserve amounts may not exceed $2.0 million), which will also reduce the amount of cash received by the trust and thereafter distributable to trust unitholders. Accordingly, higher production and development costs and expenses related to the underlying properties will directly decrease the amount of cash 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 results of the underlying properties.” Historical costs may not be indicative of future costs. In addition, cash available for distribution by the trust will be further reduced by the trust’s general and administrative expenses, which are expected to be $1.0 million in 2012. For details about these general and administrative expenses, please see “Description of the trust agreement — Fees and expenses.”

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If production and development costs on the underlying properties exceed 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 trust does not receive net proceeds pursuant to the net profits interest, or if such net proceeds are reduced, the trust will not be able to distribute cash to the trust unitholders, or such cash distributions will be reduced, respectively.

An increase in the differential or decrease in the premium 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.

Oil and natural gas production from the underlying properties is usually sold at a discount, but sometimes at a premium to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. A negative difference between the benchmark price and the price received is called a differential and a positive difference is called a premium. The differential and premium may vary significantly due to market conditions, the quality and location of production and other risk factors. Whiting cannot accurately predict oil and natural gas differentials and premiums. Increases in the differential or decreases in the premiums 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 trust units.

Financial returns to purchasers of trust units will vary in part based on how quickly 11.79 MMBOE are produced from the underlying properties and sold, and it is not known when that will occur.

The net profits interest will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold. The reserve report projects that 11.79 MMBOE will have been produced from the underlying properties and sold by December 31, 2021. 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 commodity prices are consistent with projections) because cash distributions attributable to such production will occur at a later date.

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

If the hedge payments received by Whiting and certain other non-production revenue exceed the production and development costs during a quarterly period, the ability to use such excess amounts to offset production and development costs will be deferred until the next quarterly period when such amounts are less than such costs. 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 the net profits interest terminates, then unitholders will not be entitled to receive the benefit of such excess amounts. Such a scenario could occur if oil prices decline significantly through December 31, 2014 and remained low for the remainder of the term.

The trust units may lose value as a result of title deficiencies with respect to the underlying properties.

The existence of a material title deficiency with respect to the underlying properties could reduce the value of a property or render it worthless, thus adversely affecting the net profits interest and distributions to trust unitholders. Whiting does not obtain title insurance covering mineral leaseholds, and Whiting’s failure to cure any title defects may cause Whiting to lose its rights to production from the underlying properties. In the event of any such material title problem, proceeds available for distribution to trust unitholders and the value of the trust units may be reduced.

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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 $2.0 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 on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 10.61 MMBOE in respect of the trust’s right to receive 90% of the net proceeds from such reserves pursuant to the net profits interest). The trust unitholders will not be entitled to receive any net proceeds from the sale of production from the underlying properties following the termination of the net profits interest. Therefore, the market price of the trust units will likely diminish towards the end of the term of the net profits interest because the cash distributions from the trust will cease at the termination of such net profits interest and the trust will have no right to any additional production from the underlying properties after the term of the net profits interest.

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

Whiting will own 13.0% of the trust units after this offering unless the underwriters’ over-allotment option is exercised. 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 Morgan Stanley & Co., 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 and, in addition, over time will decline to zero at termination of 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 sales prices of oil, natural gas and natural gas liquids 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

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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, and over time the market price of the trust units will decline to zero at termination of the trust.

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’s interests may conflict with those of the trust and the trust unitholders in situations involving the development, maintenance, operation or abandonment of certain wells on the underlying properties for which Whiting acts as the operator. Whiting may also make decisions with respect to development costs that adversely affect the underlying properties. These decisions include reducing development costs on properties for which Whiting acts as the operator, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the trust in the future. Additionally, Whiting’s broad discretion over the timing and amount of development, maintenance, operating expenditures and activities could result in higher costs being attributed to the net profits interest.

• 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.”

• 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.

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 a vote of 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. As a result, it may be difficult to remove or replace the trustee.

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.

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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, regional, state and local environmental and safety laws, regulations, and enforcement policies, which legal requirements have tended to become increasingly strict over time. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. 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 being imposed on Whiting with respect to its portion of the underlying properties due to the conduct of others or from Whiting’s actions even if such actions were in compliance with all applicable laws at the time those actions were taken. Private parties, including the surface estate owners of the real properties at which the underlying properties are located and the owners of facilities where petroleum hydrocarbons or wastes resulting from operations at the underlying properties are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damages. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If it were not possible to recover the resulting costs for such liabilities or non-compliance through insurance or increased revenues, then these costs could have a material adverse effect on the cash distributions to the trust unitholders. Please read “The underlying properties — Environmental matters and regulation” for more information.

The trust will indirectly bear 90% of all costs and expenses paid by Whiting, including those related to environmental compliance and liabilities associated with the underlying properties. In addition, as a result of the increased cost of compliance, the operators of the underlying properties may decide to discontinue drilling.

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.

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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.”

Climate change legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for oil and gas which could reduce the amount of cash available for distribution to trust unitholders.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public heath and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. Based on these findings, the EPA has begun adopting and implementing regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one rule that limits emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Further, facilities required to obtain PSD permits for their GHG emissions are required to reduce those emissions consistent with guidance for determining “best available control technology” standards for GHGs, which guidance was published by the EPA in November 2010. Also in November 2010, the EPA expanded its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis with reporting beginning in 2012 for emissions occurring in 2011. The underlying properties are subject to these reporting requirements.

In addition, both houses of Congress have considered legislation to reduce emissions of GHGs, and many states have already taken legal measures to reduce emissions of GHGs, primarily through the development of GHG inventories, greenhouse gas permitting and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. In the absence of new legislation, the EPA is issuing new regulations that limit emissions of GHGs associated with our operations which will require us to incur costs to inventory and reduce emissions of GHGs associated with our operations and could adversely affect demand for the oil and natural gas that Whiting produces. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect Whiting’s services.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing has been utilized in the completion of wells drilled at the underlying properties and Whiting expects it will also be used in the future. The process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel under the Safe Drinking Water Act’s Underground Injection Control Program and has commenced drafting guidance for permitting authorities and the

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industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel. Industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with initial results of the study anticipated to be available by late 2012 and final results by 2014. Moreover, the EPA recently announced in October 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy (“DOE”), the U.S. Government Accountability Office and the White House Council for Environmental Quality. The U.S. Department of the Interior is also considering regulation of hydraulic fracturing activities on public lands. In addition, legislation called the Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. For example, on June 17, 2011, Texas enacted a law that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production) and the public. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment including groundwater. In addition, if hydraulic fracturing is regulated at the federal level, Whiting’s fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays, litigation risk and potential increases in costs. Further, at least three local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities. No assurance can be given as to whether or not similar measures might be considered or implemented in the jurisdictions in which the underlying properties are located. If new laws or regulations that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in the states where the underlying properties are located, such legal requirements could make it more difficult or costly for Whiting to perform hydraulic fracturing activities and thereby could affect the determination of whether a well is commercially viable. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that Whiting is ultimately able to produce in commercially paying quantities from the underlying properties.

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 56% of the underlying properties based on the December 31, 2011 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 production from the underlying properties to fluctuations in crude oil prices in order to achieve more predictable cash flow. The crude oil collar arrangements 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.”

Whiting’s ability 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. A substantial or extended decline in oil or natural gas prices may materially and adversely affect Whiting’s future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

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 prices. In addition, because the hedge contracts are with a single counterparty, 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 prices.

The financial results of the trust may differ from the financial results of Whiting USA Trust I.

As disclosed in this prospectus, Whiting previously participated in the formation and initial public offering of Whiting USA Trust I on April 30, 2008. Given the differences in assets comprising the underlying properties, commodity prices, production and development costs, development schedule, operators of the underlying properties and regulatory environment, among other things, the historical results of operations of the 2008 trust should not be relied on as an indicator of how Whiting USA Trust II will perform. Please see “Whiting Petroleum Corporation.”

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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 the terminal production amount is 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 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 the terminal production amount to be produced from the underlying properties for purposes of the net profits interest.

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 properly treated as a production payment (and thus could fail to qualify as a debt instrument) for federal income tax purposes, the trust unitholders may receive different and potentially less advantageous tax treatment from that described in this prospectus.

If the trust were not treated as a grantor trust for federal income tax purposes, the trust should be treated as a partnership for such purposes. Although the trust would not become subject to federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the trust unitholders, the trust’s tax reporting requirements would be more complex and costly to implement and maintain, and its distributions to unitholders could be reduced as a result.

If the net profits interest were not treated as a debt instrument, any 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 “U.S. 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 that such a ruling would be granted if requested or that the IRS will not challenge this position on audit.

Thus, no assurance can be provided that the opinions and statements set forth in the discussion of U.S. federal income tax consequences would be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the trust units and the prices at which trust units trade. In addition, the costs of any contest with the IRS (whether or not such challenge is successful), principally legal, accounting and related fees, will result in a reduction in cash available for distribution to the trust unitholders, and thus will be borne indirectly by the trust unitholders.

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

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The tax treatment of an investment in trust units could be affected by recent and potential legislative, judicial or administrative changes and differing opinions, possibly on a retroactive basis.

The U.S. federal income tax treatment of an investment in our trust may be modified by administrative or legislative changes, or by judicial interpretation, at any time, possibly on a retroactive basis. For example, the Health Care and Education Affordability Reconciliation Act of 2010 includes a provision that, in taxable years beginning after December 31, 2012, subjects an individual having modified adjusted gross income in excess of $200,000 (or $250,000 for married taxpayers filing joint returns) to a “medicare tax” equal generally to 3.8% of the lesser of such excess or the individual’s net investment income, which appears to include interest income derived from investments such as the trust units as well as any net gain from the disposition of trust units. In addition, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time. Moreover, absent any new legislation affecting the matter, beginning January 1, 2013, itemized deductions that are otherwise allowable will be reduced by the lesser of (i) 3% of adjusted gross income over $100,000 ($50,000 in the case of a separate return by a married individual), as adjusted for inflation and (ii) 80% of the amount of itemized deductions that are otherwise allowable.

Trust unitholders will be required to pay taxes on their share of the trust’s income even if they do not receive any cash distributions from the trust.

Trust unitholders are treated as if they own the trust’s assets and receive the trust’s income and are directly taxable thereon as if no trust were in existence. Because the trust will generate taxable income that could be different in amount than the cash the trust distributes, the trust unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of the trust’s taxable income even if they receive no cash distributions from the trust. They may not receive cash distributions from the trust equal to their share of the trust’s taxable income or even equal to the actual tax liability that results from that income.

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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 and drilling of oil and natural gas wells;

• future production and development 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 or deflation.

You should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this prospectus. Neither Whiting nor the trust undertakes any obligation to release publicly any revisions to the forward-looking statements to reflect events or circumstances after the date of this prospectus or to reflect the occurrence of unanticipated events, unless the securities laws require it.

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 subsidiary, Whiting Oil and Gas Corporation, will convey the term net profits interest to the trust in consideration for the issuance by the trust of 18,400,000 trust units, which will be distributed as a dividend to Whiting Petroleum Corporation. Whiting will pay underwriting discounts, the structuring fee and estimated expenses of approximately $23.2 million, assuming the underwriters do not exercise their over-allotment option and an assumed initial public offering price of $20.00 per trust unit, associated with this offering and will receive all net proceeds from the offering. The estimated net proceeds to Whiting, assuming an initial public offering price of $20.00 per trust unit, will be approximately $296.8 million, and will increase to approximately $341.6 million if the underwriters exercise their over-allotment option 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 2.4% as of December 31, 2011 and mature in April 2016. Affiliates of Raymond James & Associates, Inc., Morgan Stanley & Co. LLC, J.P. Morgan Securities LLC and RBC Capital Markets, LLC are lenders under Whiting Oil and Gas Corporation’s bank credit facility and each will receive its proportionate share of the net proceeds of the offering used to repay a portion of the outstanding balance under the credit facility. Please read “Underwriting—Conflicts/affiliates.”

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WHITING PETROLEUM CORPORATION

Whiting is a publicly traded, independent oil and natural 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 2006, Whiting has focused primarily on organic drilling activity and on the development of previously acquired properties, specifically on projects that it believes provide the opportunity for repeatable successes and production growth. As of December 31, 2011, Whiting had total estimated net proved reserves of 345.2 MMBOE and during the three months ended December 31, 2011, Whiting’s average daily production was 70.7 MBOE. Whiting’s principal executive offices are located at 1700 Broadway, Suite 2300, Denver, Colorado and its telephone number is (303) 837-1661. Its website is http://www.whiting.com. Information on Whiting’s website or any other website is not incorporated by reference into this prospectus and does not constitute part of this prospectus.

The trust units do not represent interests in or obligations of Whiting.

WHITING’S EXPERIENCE WITH PRIOR NET PROFITS INTEREST TRUSTS

Whiting has sponsored one prior net profits interest trust. On April 30, 2008, Whiting completed an initial public offering of units of beneficial interest in Whiting USA Trust I (NYSE: WHX) (the “2008 trust”), a publicly traded trust. Prior to its initial public offering, Whiting conveyed a net profits interest (the “2008 net profits interest”) in certain of its oil and gas properties (the “2008 underlying properties”) to the 2008 trust in exchange for 13,863,889 trust units (the “2008 trust units”). Immediately thereafter, Whiting completed an initial public offering of units of beneficial interest in the 2008 trust, selling 11,677,500 trust units to the public at a price of $20.00 per unit. As of the date of this prospectus, Whiting retains an ownership in the 2008 trust of 2,186,389 units, or 15.8% of the total 2008 trust units issued and outstanding.

The 2008 net profits interest entitles the 2008 trust to receive 90% of the net proceeds from the sale of oil and natural gas production from the 2008 underlying properties, which are located in the Rocky Mountains, Mid-Continent, Permian, and Gulf Coast regions. The 2008 trust had proved reserves attributable to the 2008 net profits interest as of December 31, 2007 of 8.20 MMBOE, which was based on NYMEX oil and natural gas prices as of December 31, 2007 of $96.00 per Bbl of oil and $7.10 per MMBtu of natural gas, and average daily production attributable to the 2008 net profits interest for December 2007 of 4.18 MBOE per day. The 2008 net profits interest will terminate when 9.11 MMBOE (which is equivalent to 8.20 MMBOE attributable to the 2008 net profits interest) have been produced and sold from the 2008 underlying properties, regardless of the date. As of December 31, 2011, on a cumulative accrual basis, 5.00 MMBOE of the total 8.20 MMBOE have been produced and sold. Per the 2008 trust’s Current Report on Form 8-K filed with the SEC on February 7, 2012, the 9.11 MMBOE of reserves are projected to be produced by August 31, 2015, based on the 2008 trust’s reserve report for the underlying properties as of December 31, 2011. The production of 9.11 MMBOE by August 31, 2015 would result in the termination of the 2008 net profits interest more than two years prior to the December 31, 2017 termination date projected in the final prospectus relating to the initial public offering of the 2008 trust. As of March 1, 2012, the total cash distributions made by the 2008 trust were $13.16 per unit.

The final prospectus relating to the initial public offering of the 2008 trust set forth a projection for the four initial distributions relating to the twelve months ended December 31, 2008 that totaled $5.00 per 2008 trust unit. Actual distributions for the initial four distributions relating to the twelve months ended December 31, 2008, which totaled $4.897 per 2008 trust unit, were below the projected amounts outlined in such final prospectus due to the unforeseen drop in commodity prices that occurred during the latter half of 2008, primarily due to the economic downturn.

As a result of the differences in assets comprising the underlying properties, commodity prices, production and development costs, development schedule, operators of the underlying properties and regulatory environment, among other things, the historical results of operations of the 2008 trust should not be relied on as

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an indicator of how Whiting USA Trust II will perform. In particular, whereas the 2008 net profits interest will terminate upon the production and sale of 9.11 MMBOE of reserves, the net profits interest of Whiting USA Trust II will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE has been produced and sold, allowing for trust unitholders to participate in additional proceeds attributable to the net profits interest in excess of the terminal production amount should that amount be produced and sold prior to December 31, 2021. Trust unitholders should not rely on the potential early termination of the 2008 net profits interest as an indication of Whiting USA Trust II achieving the terminal production amount prior to December 31, 2021.

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THE TRUST

The trust is a statutory trust created under the Delaware Statutory Trust Act in December 2011. The business and affairs of the trust will be managed by The Bank of New York Mellon Trust Company, N.A. as trustee. Whiting has no ability to manage or influence the operations of the trust. In addition, Wilmington Trust, National Association 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 subsidiary, Whiting Oil and Gas Corporation, will convey the term net profits interest to the trust in consideration for the issuance by the trust of 18,400,000 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, 2012 to trust unitholders owning trust units on May 20, 2012. 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, 2012 through the day prior to close of this offering plus the amount payable under the net profits interest for the period from the day of closing of the offering through March 31, 2012, less any general and administrative expenses and reserves established for the benefit of the trust.

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, which may be a non-interest bearing account, and make other short-term investments with the funds distributed to the trust. The trustee has no current plans to authorize the trust to borrow money. Whiting has also agreed to post a letter of credit in the amount of $1.0 million in favor of the trustee to be used in the event that the trust has insufficient cash to pay its expenses.

The trust will pay the trustee an administrative fee of $175,000 per year, which escalates annually by 2.5% starting in 2017. 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. The trust will also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual and quarterly reports to unitholders, tax return and Form 1099 preparation and distribution, NYSE listing fees, independent auditor fees and registrar and transfer agent fees. Total general and administrative expenses of the trust are expected to be approximately $1.0 million in 2012 and annually thereafter, including the administrative services fee payable to Whiting described below.

The net profits interest will terminate on the later to occur of (1) December 31, 2021, or (2) the time when the terminal production amount has been produced and sold, 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 will enter into an administrative services agreement with Whiting that will obligate 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 its net interests in certain oil and natural gas producing properties, which properties are located primarily in the Rocky Mountains, Permian Basin, Gulf Coast and Mid-Continent 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 later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 10.61 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;

• lease operating expenses and property taxes;

• development costs;

• production taxes;

• maintenance expenses;

• post production costs, including costs to process natural gas into natural gas liquids;

• reserves by Whiting for future development, maintenance or operating expenses;

• administrative expenses of the trust; and

• cash reserves of the trust.

UNAUDITED PRO FORMA CASH DISTRIBUTION ON TRUST UNITS FOR EACH OF THE FOUR QUARTERS ENDED DECEMBER 31, 2011

The following unaudited pro forma cash distribution on trust units give effect to the trust formation and net profits interest conveyance as if they occurred as of January 1, 2011. Whiting believes that the assumptions used provide a reasonable basis for presenting the effects directly attributable to this transaction. However, the pro forma amounts set forth in the table below are for informational purposes only and do not purport to present cash distributions by the trust to trust unitholders had the trust formation and net profits interest conveyance actually occurred on January 1, 2011 or for the periods presented or which may be realized in the future. Cash distributions on trust units will be calculated based upon actual cash receipts of the trust during the applicable quarter for which a cash distribution is being made. Therefore, the unaudited pro forma cash distributions on trust units have been prepared using a modified cash basis of accounting as described in more detail in Note 2 to the unaudited pro forma financial statements appearing on page F-17.

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Unaudited Pro Forma Cash Distributions on Trust Units

	Quarter Ended
	March 31, 2011			June 30, 2011			September 30, 2011			December 31, 2011
	(dollars in thousands, except per trust unit amounts)
Underlying properties sales volumes:
Oil and natural gas liquids (MBbl)		350			361			347			351
Natural gas (MMcf)		770			786			670			659
Realized sales price:
Oil (per Bbl)	$	74.98		$	83.27		$	94.71		$	82.98
Natural gas (per Mcf)	$	5.30		$	5.83		$	6.31		$	6.44
Calculation of net proceeds:
Gross proceeds:
Oil and natural gas liquids sales	$	26,220		$	30,084		$	32,878		$	29,121
Natural gas sales		4,083			4,581			4,230			4,245
Total	$	30,303		$	34,665		$	37,108		$	33,366
Production and development costs:
Lease operating costs	$	10,805		$	8,430		$	9,510		$	9,632
Production taxes		1,715			1,895			2,037			1,530
Development costs		5,388			2,896			5,463			3,546
Total	$	17,908		$	13,221		$	17,010		$	14,708
Net proceeds	$	12,395		$	21,444		$	20,098		$	18,658
Percentage allocable to net profits interest		90	%		90	%		90	%		90	%
Total cash proceeds to trust	$	11,156		$	19,300		$	18,088		$	16,791
Trust administrative expenses(1)		(94	)		(94	)		(94	)		(93	)
Cash distributable on trust units before state income tax withholdings	$	11,062		$	19,206		$	17,994		$	16,698
State income tax withholdings		(27	)		(17	)		(30	)		(20	)
Cash distributions on trust units	$	11,035		$	19,189		$	17,964		$	16,678
Cash distributions per trust unit before state income tax withholdings	$	0.60		$	1.04		$	0.98		$	0.91
Cash distributions per trust unit	$	0.60		$	1.04		$	0.98		$	0.91

(1) The trust will pay an annual administrative fee to Whiting of $200,000 and an annual administrative fee to the trustee of $175,000. Including the above administrative fees of $375,000 to Whiting and the trustee, the trust estimates incurring aggregate general and administrative expenses of $1.0 million in 2012 and annually thereafter, as described in “The trust.” If the estimated general and administrative expenses were included in the table above, the cash distribution on trust units would be approximately $10.9 million (or $0.59 per unit), $19.0 million (or $1.03 per unit), $17.8 million (or $0.97 per unit) and $16.5 million (or $0.90 per unit) for the quarters ended March 31, 2011, June 30, 2011, September 30, 2011 and December 31, 2011, respectively. Due to the omission of general and administrative expenses other than the $375,000 of administrative fees from cash distribution on trust units, these pro forma financial amounts may not be indicative of the results to be realized going forward.

PROJECTED CASH DISTRIBUTIONS FOR THE YEAR ENDING DECEMBER 31, 2012

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 liquids production for the first quarter of 2012 and continue to own those trust units through the record date for the cash distributions payable with respect to oil, natural gas and natural gas liquids production for the last

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quarter of 2012. The table also reflects the methodology for calculating the projected cash distributions. The cash distribution projections were prepared by Whiting for each of the four quarters in 2012 and the twelve months ending December 31, 2012 based on the hypothetical assumptions that are described in “— Significant assumptions used to prepare the projected cash distributions” below. Actual cash distributions 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 or other third parties, 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 liquids production and operating expenses, based on:

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

• production and development costs and reserves by Whiting for future development, maintenance and operating expenditures for the twelve months ending December 31, 2012.

The projected cash distributions are based upon assumptions related to commodity prices. Oil prices underlying the assumed reference prices in the projected cash distributions table for the months of January and February 2012 are based on average daily WTI Cushing crude oil spot prices for each month (with the February reference price being the average daily price through February 24, 2012). For the balance of 2012, the assumed reference price for oil is the average of the settled NYMEX price for oil for the month of March and the NYMEX futures prices for oil for April through December, as reported on February 24, 2012. 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. Natural gas prices underlying the assumed reference prices in the projected cash distributions table for the months of January and February 2012 are based on actual settled NYMEX prices for natural gas. For the balance of 2012, the assumed reference price for natural gas is the average of the NYMEX futures prices for natural gas for March through December, each as reported on February 24, 2012. Published NYMEX benchmark prices for natural gas are based upon delivery at the Henry Hub in Louisiana. The assumed reference prices for natural gas liquids are equal to approximately 68% of the assumed reference price for oil for the corresponding month, which is consistent with the historical pricing realized by Whiting for its natural gas liquids.

The assumed realized sales prices for oil, natural gas and natural gas liquids are adjusted to reflect differentials, which are the average differences between NYMEX published prices and the prices received by Whiting during the year ended December 31, 2011. For more information about differential assumptions, please see “—Significant assumptions used to prepare the cash distributions — Oil, natural gas and natural gas liquids prices.”

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Actual prices paid for oil, natural gas and natural gas liquids expected to be produced from the underlying properties in 2012 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 average of the monthly closing NYMEX crude oil spot prices per Bbl was $97.00 from January 1, 2011 through December 31, 2011, with the monthly closing prices ranging from $79.20 to $113.93 during such period. See “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 liquids prices, subject to the hedge contracts. The hedge contracts will limit the potential for increases in cash distributions due to oil price increases from April 1, 2012 through December 31, 2014.”

In preparing the projected financial information, Whiting utilized the production estimates, hypothetical oil, natural gas and natural gas liquids prices and cost estimates as described above. However, the actual production amounts, commodity prices and costs for 2012 may differ materially from these estimates and assumptions.

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 liquids prices. See “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 liquids prices, subject to the hedge contracts. The hedge contracts will limit the potential for increases in cash distributions due to oil price increases from April 1, 2012 through December 31, 2014” and “Projected cash distributions — Sensitivity of projected cash distributions to oil, natural gas and natural gas liquids 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 for 2012 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 liquids 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 8.4% between 2012 and 2021, assuming no additional development drilling or other development expenditures are made on the underlying properties after 2014. 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 or if expected future development is delayed, reduced or cancelled. 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 Liquids

Production in Reserve Report(1)

	Quarter Ending												Year Ending December 31, 2012
	March 31, 2012			June 30, 2012			September 30, 2012			December 31, 2012
	(dollars in thousands, except per Bbl, Mcf, MMBtu and trust unit amounts)
Underlying properties sales volumes:
Oil and natural gas liquids (MBbl)		304			323			319			313			1,259
Natural gas (MMcf)		394			635			609			590			2,228
Assumed reference price:
Oil (per Bbl)	$	104.05		$	109.87		$	109.87		$	109.87		$	108.44
Natural gas (per MMBtu)	$	2.85		$	2.98		$	2.98		$	2.98		$	2.96
Assumed realized sales price:
Oil (per Bbl)	$	94.05		$	99.93		$	100.12		$	100.21		$	98.54
Natural gas (per Mcf)	$	4.17		$	4.26		$	4.30		$	4.32		$	4.27
Calculation of net proceeds:
Gross proceeds:
Oil and natural gas liquids sales	$	28,590		$	32,276		$	31,937		$	31,265		$	124,068
Natural gas sales		1,643			2,705			2,620			2,551			9,519
Total	$	30,233		$	34,981		$	34,557		$	33,816		$	133,587
Production and development costs:
Lease operating expenses	$	9,117		$	9,094		$	9,080		$	9,059		$	36,350
Production taxes		1,591			2,001			1,983			1,939			7,514
Development costs		1,280			702			3,275			1,049			6,306
Payments made (or received) by Whiting to settle hedge contracts(2)		—			—			—			—			—
Total	$	11,988		$	11,797		$	14,338		$	12,047		$	50,170
Whiting expense reserve(3)		—			—			—			—			—
Net proceeds	$	18,245		$	23,184		$	20,219		$	21,769		$	83,417
Percentage allocable to net profits interest		90	%		90	%		90	%		90	%		90	%
Total cash proceeds to trust	$	16,420		$	20,866		$	18,197		$	19,592		$	75,075
Trust administrative expenses(4)		(250	)		(250	)		(250	)		(250	)		(1,000	)
Projected cash distributions on trust units before state income tax withholdings and reserve for future trust expenses	$	16,170		$	20,616		$	17,947		$	19,342		$	74,075
Trustee reserve for future trust expenses(5)		—			—			—			—			—
State income tax withholdings(6)		(20	)		(19	)		(18	)		(16	)		(73	)
Projected cash distributions on trust units	$	16,150		$	20,597		$	17,929		$	19,326		$	74,002
Projected cash distributions per trust unit before state income tax withholdings and reserve for future trust expenses	$	0.88		$	1.12		$	0.97		$	1.05		$	4.02
Projected cash distributions per trust unit	$	0.88		$	1.12		$	0.97		$	1.05		$	4.02

(1) The cash distributions projections were prepared by Whiting on a cash basis based on hypothetical assumptions. Actual cash distributions may vary from those presented. For more information about the hypothetical assumptions made in preparing the table above, including the impact of the time lag in receiving oil, natural gas and natural gas liquids sales proceeds, see “— Significant assumptions used to prepare the projected cash distributions” below.

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(2) Production and development costs will be reduced by hedge payments and other non-production revenue received by Whiting under the hedge contracts. If the hedge payments and other non-production revenue received by Whiting under the hedge contracts exceed production and development costs during a quarterly period, the use of such excess amounts to offset costs will be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period when the current and deferred hedge payments and other non-production revenue are less than the applicable production and development costs.

(3) Whiting may reserve from the gross proceeds from sales of production amounts up to $2.0 million at any time for future development, maintenance or operating expenses. However, Whiting does not anticipate funding such reserve between January 1, 2012 and December 31, 2012, but plans on deducting from the net proceeds only actual costs paid for development, maintenance and operating expenses.

(4) Total general and administrative expenses of the trust on an annualized basis for 2012 are expected to be $1.0 million, which includes an annual administrative services fee to Whiting in the amount of $200,000, the annual fee to the trustees, accounting fees, engineering fees, printing costs and other expenses properly chargeable to the trust.

(5) The trustee may reserve from the cash distribution funds to pay for future trust expenses. However, the trustee does not anticipate funding such reserve between January 1, 2012 and December 31, 2012.

(6) Represents projected withholding for the state of Montana. See “State tax considerations.”

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.” Quarterly cash distributions will be made 60 days following the end of each calendar quarter (or the next succeeding business day) to trust unitholders of record on the 50th day following the end of each calendar quarter. Due to the time lag in receiving oil, natural gas and natural gas liquids sales proceeds, a portion of the net proceeds from one month of oil sales and a portion of the net proceeds from two months, including all of one month, of natural gas and natural gas liquids sales are not included in the distribution with respect to each quarter presented, as well as the full year presented. Instead, such amounts are included in the distribution for the following quarter or year, as applicable. However, the projected distribution for each quarter, as well as for the full year, include all production and development costs incurred in such period.

The first distribution, which will cover the first quarter of 2012, is expected to be made on or about May 30, 2012 to record trust unitholders as of May 20, 2012, and will include sales for oil for the months January through a portion of March 2012, and natural gas and natural gas liquids for the months January through a portion of February 2012. Thereafter, quarterly distributions will generally relate to production of oil, natural gas and natural gas liquids for a three month period, including one month of natural gas production from the prior quarter.

Production estimates.    Production estimates for 2012 are based on the reserve report. The reserve report assumed oil and natural gas prices calculated using an average of the first-day-of-the month price for each month within the 12 months ended December 31, 2011, which equaled $96.19 per Bbl of oil ($87.25 per Bbl field adjusted price inclusive of the effects of natural gas liquids), $4.12 per MMBtu ($6.00 field adjusted price per Mcf) of natural gas. The average first-day-of-the month price for the 12 months ended December 31, 2011 applied to natural gas liquids was $69.61 per Bbl. Production from the underlying properties for 2012 is estimated to be 1,259 MBbls of oil and 2,228 MMcf of natural gas. See “— Oil, natural gas and natural gas liquids 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 8.4% between 2012 and 2021, assuming no additional development drilling or other development expenditures are made on the underlying properties after 2014. Differing levels of development drilling or other development expenditures or production will result in different levels of distributions and cash returns.

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When oil, natural gas and natural gas liquids prices decline, the operators of the underlying properties may elect to reduce or completely suspend production. The projections assume no such reductions or suspensions of production occur in 2012.

Oil, natural gas and natural gas liquids prices.    The hypothetical assumed reference prices for oil, natural gas and natural gas liquids included in the projected cash distributions table are based on the following:

• For the months of January and February 2012, the assumed reference prices for oil are equal to the average daily WTI Cushing crude oil spot prices for each month (with the February reference price being the average daily price through February 24, 2012), or $100.29 per Bbl and $101.30 per Bbl, respectively;

• For the balance of 2012, the assumed reference price for oil is the average of the settled NYMEX price for oil for the month of March and the NYMEX futures prices for oil for April through December, as reported on February 24, 2012, or $109.87 per Bbl;

• For the months of January and February 2012, the assumed reference prices for natural gas are equal to the settled NYMEX prices for natural gas, or $3.08 per MMBtu and $2.68 per MMBtu, respectively;

• For the balance of 2012, the assumed reference price for natural gas is the average of the NYMEX futures prices for natural gas for March through December, each as reported on February 24, 2012, or $2.98 per MMBtu; and

• For 2012, the assumed reference prices for natural gas liquids are equal to approximately 68% of the assumed reference price for oil for the corresponding month, which is consistent with the historical pricing realized by Whiting for its natural gas liquids.

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 assumed reference 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 cash distribution table, approximately $8.80 per Bbl is deducted from the assumed sales price for crude oil to reflect the differential, which is based on 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, 2011. 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 2012. Assumed average oil prices appearing in this prospectus have been adjusted for these differentials. Because there is no hedge in place for natural gas liquids, Whiting used a hypothetical price equal to approximately 68% of the assumed reference price used in the projected cash distributions table for oil, which is consistent with the historical pricing realized by Whiting for natural gas liquids.

In the cash distribution table, approximately $1.31 per Mcf is added to the assumed sales price for natural gas in 2012 to reflect the differential, which is based on 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, 2011. This addition 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 2012.

The adjustments to the assumed reference oil, natural gas and natural gas liquids prices applied in the above projected cash distributions estimate are based upon an analysis by Whiting of the historic price differentials relative to NYMEX benchmark prices for production from the underlying properties with consideration given to gravity, quality and transportation and marketing costs that may affect these differentials in 2012. There is no assurance that these assumed differentials will occur in 2012.

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Settlement of hedge contracts.    Whiting has entered into costless collar arrangements with respect to          Bbls of oil expected to be produced from the underlying properties during 2012. The hedge contracts are priced with floors of $80.00 and ceilings of $122.50 per Bbl of oil. 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 prices assumed in the projected cash distributions table.

Production and development costs and reserve.    For 2012, Whiting estimates lease operating expenses and property taxes to be $36.4 million, which is 9% higher than estimated in the reserve report due to higher expected workover costs. For 2011, lease operating expenses and property taxes were $39.4 million. Additionally, for 2012, Whiting estimates production taxes to be $7.5 million, which compares to $7.5 million for 2011. Whiting estimates development costs to be $6.3 million, which is based on Whiting’s development plans for the underlying properties for which it operates and information provided by other operators for the underlying properties not operated by Whiting, and assumes that Whiting and other operators do not increase capital expenditure budgets. Additionally, although Whiting may reserve from the gross proceeds up to $2.0 million for future development, maintenance and operating expenses, Whiting does not anticipate funding such reserve between January 1, 2012 and December 31, 2012, but plans on deducting from the net proceeds only actual costs paid for development, maintenance and operating expenses. For a description of production expenses and the reserve, see “Computation of net proceeds — Net profits interest.”

Administrative expense.    Trust administrative expense for 2012 is expected to be $1.0 million. See “The trust.”

SENSITIVITY OF PROJECTED CASH DISTRIBUTIONS TO OIL, NATURAL GAS AND NATURAL GAS LIQUIDS 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 liquids 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, development costs and production and property taxes.

The tables below set forth sensitivity analyses of annual cash distributions per trust unit for the quarters ending March 31, 2012, June 30, 2012, September 30, 2012 and December 31, 2012, and the year ending December 31, 2012, on the assumption that a trust unitholder purchased a trust unit on January 1, 2012, and held such trust unit until the quarterly record date for distributions made with respect to oil, natural gas and natural gas liquids production in the applicable period, based upon: (1) the assumption that a total of 18,400,000 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) various hypothetical assumed reference commodity prices as described above under “— Significant assumptions used to prepare the projected cash distributions — Oil, natural gas and natural gas liquids prices”; (4) the impact of the hedge contracts entered into by Whiting that relate to production from the underlying properties; and (5) other assumptions described above under “— Significant assumptions used to prepare the projected cash distributions.” The hypothetical commodity prices of oil, natural gas and natural gas liquids production shown have been chosen solely for illustrative purposes and do not give effect to potential changes in differentials associated with price fluctuations.

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 (giving effect to the hedge contracts that are in place in 2012). There is no assurance that the hypothetical assumptions described below will actually occur or that production or assumed reference prices will not change by amounts different from those shown in the tables.

Whiting has entered into certain hedge contracts related to the oil production from the underlying properties for the period from April 1, 2012 through December 31, 2014. These hedge contracts are costless collar

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arrangements that hedge approximately 50% of the anticipated oil production attributable to the underlying properties. The crude oil hedge contracts are priced with floors of $80.00 and ceilings of $122.50 per Bbl of oil. Whiting will not enter into any hedge contracts related to natural gas production from the underlying properties. Additionally, Whiting will not enter into any hedge contracts related to production from the underlying properties for periods after 2014 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.

Sensitivity of 2012 Projected Cash Distributions Per Trust Unit

to Changes in Estimated Oil and Natural Gas Production and Assumed Reference Prices

			Quarter Ending March 31, 2012 Projected Distributions Per Unit         % of Assumed Reference Prices(2)
			70%		80%		90%		100%		110%		120%		130%
	85	%	$	0.35	$	0.48	$	0.60	$	0.73	$	0.85	$	0.98	$	1.11
	90	%		0.38		0.51		0.65		0.78		0.91		1.04		1.18
	95	%		0.41		0.55		0.69		0.83		0.97		1.11		1.25
	100	%		0.44		0.58		0.73		0.88		1.03		1.17		1.32
	105	%		0.46		0.62		0.77		0.93		1.08		1.24		1.39
	110	%		0.49		0.65		0.81		0.98		1.14		1.30		1.46
	115	%		0.52		0.69		0.86		1.03		1.20		1.37		1.54

			Quarter Ending June 30, 2012 Projected Distributions Per Unit     % of Assumed Reference Prices(3)
			70%		80%		90%		100%		110%		120%		130%
	85	%	$	0.53	$	0.65	$	0.79	$	0.94	$	1.08	$	1.16	$	1.23
	90	%		0.56		0.69		0.85		1.00		1.15		1.24		1.31
	95	%		0.60		0.74		0.90		1.06		1.22		1.31		1.40
	100	%		0.63		0.78		0.95		1.12		1.29		1.39		1.48
	105	%		0.67		0.82		1.00		1.18		1.36		1.47		1.57
	110	%		0.70		0.87		1.05		1.24		1.43		1.55		1.65
	115	%		0.74		0.91		1.11		1.30		1.49		1.62		1.74

			Quarter Ending September 30, 2012 Projected Distributions Per Unit     % of Assumed Reference Prices(3)
			70%		80%		90%		100%		110%		120%		130%
	85	%	$	0.39	$	0.51	$	0.65	$	0.80	$	0.94	$	1.02	$	1.08
	90	%		0.43		0.55		0.71		0.86		1.01		1.09		1.16
	95	%		0.46		0.60		0.76		0.92		1.07		1.17		1.25
	100	%		0.49		0.64		0.81		0.97		1.14		1.24		1.33
	105	%		0.53		0.68		0.86		1.03		1.21		1.32		1.42
	110	%		0.56		0.72		0.91		1.09		1.28		1.40		1.50
	115	%		0.60		0.77		0.96		1.15		1.34		1.47		1.59

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			Quarter Ending December 31, 2012 Projected Distributions Per Unit     % of Assumed Reference Prices(3)
			70%		80%		90%		100%		110%		120%		130%
	85	%	$	0.48	$	0.60	$	0.74	$	0.88	$	1.02	$	1.09	$	1.16
	90	%		0.51		0.64		0.79		0.94		1.08		1.17		1.24
	95	%		0.55		0.68		0.84		0.99		1.15		1.24		1.32
	100	%		0.58		0.72		0.89		1.05		1.21		1.31		1.40
	105	%		0.61		0.76		0.94		1.11		1.28		1.39		1.48
	110	%		0.65		0.81		0.99		1.17		1.35		1.46		1.57
	115	%		0.68		0.85		1.03		1.22		1.41		1.54		1.65

			Year Ending December 31, 2012 Projected Distributions Per Unit     % of Assumed Reference Prices (4)(5)
			70%		80%		90%		100%		110%		120%		130%
	85	%	$	1.75	$	2.24	$	2.79	$	3.34	$	3.89	$	4.25	$	4.57
	90	%		1.88		2.40		2.99		3.57		4.15		4.54		4.89
	95	%		2.01		2.56		3.18		3.80		4.41		4.83		5.21
	100	%		2.14		2.73		3.37		4.02		4.67		5.12		5.54
	105	%		2.27		2.89		3.57		4.25		4.93		5.41		5.86
	110	%		2.40		3.05		3.76		4.48		5.19		5.70		6.19
	115	%		2.53		3.21		3.96		4.70		5.45		6.00		6.51

(1) Estimated oil and natural gas production is based on the reserve report, and the sensitivity analysis assumes there will be no variation by location and that oil and natural gas production will continue to represent the same percentage of total production as estimated in the reserve report.

(2) Based on an assumed reference price of $104.05 per Bbl in the case of oil and $2.85 per MMBtu in the case of natural gas.

(3) Based on an assumed reference price of $109.87 per Bbl in the case of oil and $2.98 per MMBtu in the case of natural gas.

(4) Based on an assumed reference price of $108.44 per Bbl in the case of oil and $2.96 per MMBtu in the case of natural gas.

(5) For year ending December 31, 2012 projected distributions per unit to equal zero, realized oil, natural gas and natural gas liquids prices would need to fall approximately 80% below the forecasted prices.

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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 long-lived, predominately producing properties located primarily in the Rocky Mountains, Permian Basin, Gulf Coast and Mid-Continent regions of the United States. The underlying properties include interests in 1,300 gross (390.3 net) producing wells located in 49 predominantly mature fields with established production profiles in 10 states. As of December 31, 2011, approximately 96.4% of estimated proved reserves attributable to the underlying properties during the estimated term of the net profits interest were classified as proved developed producing reserves, 2.3% were classified as proved developed non-producing reserves and 1.3% were classified as proved undeveloped reserves. For the three months ended December 31, 2011, the average daily net production from the underlying properties was approximately 4,988 BOE/d (or 4,489 BOE/d attributable to the net profits interest) and was comprised of approximately 72% oil, 25% natural gas and 3% natural gas liquids. Whiting operates approximately 59% and 56% of the estimated proved reserve volumes and pre-tax PV10% value, respectively, of these properties based on the reserve report.

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, 2011, the total estimated proved reserves attributable to the underlying properties, as estimated in the reserve report, were approximately 18.28 MMBOE with a pre-tax PV10% value of $408.5 million. The net profits interest entitles the trust to receive 90% of the net proceeds from the sale of production until the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold. The 11.79 MMBOE amount represents the estimated proved reserves attributable to the underlying properties that the reserve report projects to be produced by December 31, 2021. The exact rate of production attributable to the underlying properties cannot be predicted. However, because the term of the trust continues until the later of December 31, 2021 or the time when the terminal production amount has been produced and sold, trust unitholders will have the right to participate in additional proceeds attributable to the underlying properties in excess of 10.61 MMBOE in the event such amount is produced and sold prior to December 31, 2021. 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. As of December 31, 2011 and assuming its continued ownership of the underlying properties, the total estimated proved reserves attributable to Whiting’s remaining interest in the underlying properties at the termination of the net profits interest, as estimated in the reserve report, are expected to be 6.49 MMBOE, or approximately 35.5% of the estimated proved reserves attributable to the underlying properties.

Whiting believes that its retained interest in the underlying properties, which entitles it to 10% of the net proceeds from the sale of production attributable to the underlying properties during the term of the net profits interest and all of the net proceeds thereafter, together with its ownership of trust units, if any, will provide incentive for it to operate (or cause to be operated) the underlying properties in an efficient and cost-effective

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manner. In addition, Whiting has agreed to operate the properties for which it is the operator as a reasonably prudent operator in the same manner that it would operate if these properties were not burdened by the net profits interest. Furthermore, for those properties for which it is not the operator, Whiting has agreed to use commercially reasonable efforts to cause the operator to operate the property in the same manner; however, Whiting’s ability to cause other operators to take certain actions is limited. Please see “Risk factors — Whiting has limited control over activities on the underlying properties that Whiting does not operate, which could reduce production from the underlying properties, increase capital expenditures and reduce cash available for distribution to trust unitholders.”

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 8.4% from 2012 through 2021, assuming no additional development drilling or other development expenditures are made on the underlying properties after 2014. 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 or if expected future development is delayed, reduced or cancelled.

HISTORICAL RESULTS OF THE UNDERLYING PROPERTIES

The selected financial data presented below should be read in conjunction with the audited statements of historical revenues and direct operating expenses and the unaudited statements of historical revenues and direct operating expenses of the underlying properties, the related notes and “— Discussion and analysis of historical results of the underlying properties” included elsewhere in this prospectus. The following table sets forth revenues, direct operating expenses and the excess of revenues over direct operating expenses relating to the underlying properties for the three years in the period ended December 31, 2011, derived from the underlying properties’ audited and unaudited statements of historical revenues and direct operating expenses included elsewhere in this prospectus. The unaudited statements were prepared on a basis consistent with the audited statements and, in the opinion of Whiting, include all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the revenues, direct operating expenses and the excess of revenues over direct operating expenses relating to the underlying properties for the periods presented.

	Year Ended December 31,
	2009 (as restated)		2010 (as restated)		2011
	(dollars in thousands)
Revenues:
Oil sales(1)	$	85,826	$	104,667	$	120,879
Natural gas sales		19,791		19,041		16,893
Total revenues	$	105,617	$	123,708	$	137,772
Direct operating expenses:
Lease operating	$	35,076	$	37,391	$	39,377
Production taxes		5,718		6,571		7,536
Total direct operating expenses	$	40,794	$	43,962	$	46,913
Excess of revenues over direct operating expenses	$	64,823	$	79,746	$	90,859

(1) Includes natural gas liquids.

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The following table provides unaudited 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, 2011. 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.

	Year Ended December 31,
	2009		2010		2011
Net sales volumes:
Oil (MBbl)(1)		1,572		1,459		1,382
Natural gas (MMcf)		4,318		3,335		2,717
Total sales volumes (MBOE)		2,292		2,015		1,834
Average realized sales prices:
Oil (per Bbl)(1)	$	54.60	$	71.74	$	87.47
Natural gas (per Mcf)	$	4.58	$	5.71	$	6.22
Capital expenditures (in thousands)	$	20,229	$	25,969	$	19,424

(1) Includes natural gas liquids.

PRO FORMA DISTRIBUTABLE INCOME FOR THE TRUST

The summary financial data presented below should be read in conjunction with the unaudited pro forma financial statements and related notes beginning on F-14. This pro forma data gives effect to the trust formation and the conveyance of the term net profits interest in the underlying properties to the trust by Whiting as if they occurred January 1, 2011. Whiting believes that the assumptions used provide a reasonable basis for presenting the effects directly attributable to this transaction. The summary financial data presented below is for information purposes only. It does not purport to present the results that would have actually occurred had the net profits interest conveyance been completed on the assumed date or for the period presented or which may be realized in the future.

	Year Ended December  31, 2011
	(dollars in thousands, except per unit amount)
Historical results
Income from Net Profits Interest	$	65,335
Pro Forma Adjustments
Less:
Trust general and administrative expenses		(375	)
State income tax withholdings		(94	)
Distributable income	$	64,866
Distributable income per trust unit	$	3.53

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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, 2011 compared to the year ended December 31, 2010

Revenues.    Oil and natural gas sales revenue increased $14.1 million from 2010 to 2011. Sales are a function of average sales prices and volumes sold. The average prices realized for oil and natural gas increased 22% and 9%, respectively, between periods. Oil sales volumes decreased 5% or 77 MBbl between periods primarily due to normal field production decline. Natural gas sales volumes decreased 19% or 618 MMcf between periods. The primarily cause of this larger decrease in natural gas volumes was related to six wells that experienced higher than average production decline rates in 2010 and 2011. Production from these six wells decreased 348 MMcf in 2011 compared to 2010. These six wells were drilled and completed in the latter portion of 2008 and were therefore in their initial steep decline phases during 2010 and 2011 following their completion. Steep initial decline is normal for natural gas wells drilled into tight gas reservoirs, and we anticipate future decline rates for these wells to be more moderate going forward. In addition, there were nine wells that were shut-in for a portion of 2011, experienced temporary production downtime or had gas gathering systems go offline, which contributed an additional 128 MMcf of natural gas production decreases in 2011. Normal field production decline of 243 MMcf also contributed to the decrease in natural gas volumes produced during 2011. These natural gas production decreases were partially offset by an increase of 101 MMcf between periods due to eight new wells drilled in the latter half of 2010 and early 2011.

Lease operating expenses.    Lease operating expenses (“LOE”) increased $2.0 million from 2010 to 2011, and lease operating expenses per BOE increased from $18.56 during 2010 to $21.46 during 2011. The $2.0 million increase in LOE was primarily caused by a high level of workover activity in 2011, as well as increases in field labor costs, contract services and LOE being charged by other operators on properties that Whiting does not operate. Workovers amounted to $6.7 million in 2011, as compared to $6.0 million in 2010; however, Whiting cannot provide any assurance that workovers will continue to occur at this level. In addition, field labor costs increased $0.5 million due to higher salaries and wages in 2011, fees paid to outside contractors for equipment and services increased $0.4 million from 2010 to 2011, and LOE charged by outside operators increased $0.4 million between periods.

Production taxes.    Production taxes are calculated as a percentage of oil and natural gas sales revenue. Credits and exemptions allowed in the various taxing jurisdictions are generally utilized to their potential. Production tax rates for 2011 and 2010 were consistent between periods at approximately 5% of oil and natural gas sales.

Excess of revenues over direct operating expenses.    Excess of revenues over direct operating expenses increased $11.1 million from 2010 to 2011. The reasons for this increase included a 22% increase in oil prices and a 9% increase in natural gas prices between periods. The increased pricing was partially offset by a 9% decrease in equivalent volumes sold, higher lease operating expenses and production taxes in 2011.

Comparison of results of the underlying properties for the year ended December 31, 2010 compared to the year ended December 31, 2009

Revenues.    Oil and natural gas sales revenue increased $18.1 million from 2009 to 2010. Sales are a function of average sales prices and volumes sold. The average prices realized for oil and natural gas increased 31% and 25%, respectively, between periods. Oil sales volumes decreased 7% or 113 MBbl between periods primarily due to normal field production decline, while total natural gas sales volumes decreased 23% or 983 MMcf from 2009 to 2010. Six wells drilled in latter 2008 had higher than average decline rates totaling 847 MMcf, as these wells were in their initial steep decline phases following their completion. Steep initial decline is normal for natural gas wells drilled into tight gas reservoirs. In addition, there were production decreases of 347 MMcf related mainly to normal field production decline and production decreases of 29 MMcf related to three wells that were shut-in for a portion of 2010. These production decreases were partially offset by natural gas production increases totaling 240 MMcf. Eight new wells drilled in the latter half of 2009 and early 2010 added

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incremental natural gas production of 109 MMcf in 2010. In addition, two wells experienced reservoir pressure drops which in turn had the effect of producing higher natural gas volumes relative to oil, and this event increased natural gas production by 66 MMcf in 2010 for these two wells. Well workovers performed on another two wells in 2010 resulted in natural gas production increases of 45 MMcf between periods. Lastly, a well that was shut-in for a portion of 2009 had incrementally higher natural gas production of 20 MMcf in 2010.

Lease operating expenses.    Lease operating expenses increased $2.3 million from 2009 to 2010, and lease operating expenses per BOE increased from $15.31 during 2009 to $18.56 during 2010. The increase of 21% on a BOE basis was primarily caused by a high level of workover activity in 2010, an increase in fees of $1.1 million paid to outside contractors for services and equipment and a decrease in production volumes between periods. Workovers amounted to $6.0 million in 2010, as compared to $3.4 million in 2009; however, Whiting cannot provide any assurance that workovers will continue to occur at these levels. In addition, overall oil and natural gas production volumes decreased by 277 MBOE between periods. All of these factors resulting in LOE increases were partially offset by various cost declines amounting to $1.4 million that were generally associated with lower 2010 production levels.

Production taxes.    Production taxes are calculated as a percentage of oil and natural gas sales revenue. Credits and exemptions allowed in the various taxing jurisdictions are generally utilized to their potential. Production tax rates for 2009 and 2010 were consistent between periods at 5% of oil and natural gas sales.

Excess of revenues over direct operating expenses.    Excess of revenues over direct operating expenses increased $14.9 million from 2009 to 2010. The reasons for this increase included a 31% increase in oil prices and a 25% increase in natural gas prices between periods. The increased pricing was partially offset by a 12% decrease in equivalent volumes sold and higher lease operating expenses and production taxes in 2010.

HEDGE CONTRACTS

The revenues derived from the underlying properties depend substantially on prevailing crude oil, natural gas and natural gas liquids 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 liquids production from the underlying properties under floating market price contracts each month. Whiting has entered into hedge contracts, which are structured as costless collar arrangements, to hedge approximately 50% of the anticipated oil production from the reserves attributable to the underlying properties in the reserve report for the period from April 1, 2012 through December 31, 2014. During the term of the hedge contracts, Whiting expects these contracts will reduce the oil price-related risks inherent in holding interests in oil properties, although they will also limit the potential for upside during the hedged period if oil prices increase. Trust unitholders will be exposed to fluctuations in prices of natural gas throughout the term of the trust, and after the hedge contracts cease to exist on January 1, 2015, trust unitholders’ exposure to fluctuations in oil prices will increase. Because the trust is intended to qualify as a grantor trust for U.S. federal income tax purposes, it is generally prohibited from varying or reinvesting its assets. Permitting Whiting to enter into additional hedge arrangements after the closing of this offering relating to production from the underlying properties could be treated as the trust constructively retaining the right to vary its assets. Accordingly, under the terms of the conveyance, Whiting will be prohibited from entering into hedging arrangements covering the production from the underlying properties following the completion of this offering. The hedge contracts will be placed with a single trading counterparty. Whiting cannot provide assurance that this trading counterparty will not become a credit risk in the future.

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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, 2012 through December 31, 2014, Whiting’s crude oil price risk management positions in collar arrangements are as follows:

	Oil Collars
	Volumes (Bbls)		Weighted Average Price (per Bbl)
			Floor		Ceiling
April 2012		48,400	$	80.00	$	122.50
May 2012		48,400	$	80.00	$	122.50
June 2012		48,400	$	80.00	$	122.50
July 2012		47,900	$	80.00	$	122.50
August 2012		47,900	$	80.00	$	122.50
September 2012		47,900	$	80.00	$	122.50
October 2012		46,800	$	80.00	$	122.50
November 2012		46,800	$	80.00	$	122.50
December 2012		46,800	$	80.00	$	122.50
January 2013		45,600	$	80.00	$	122.50
February 2013		45,600	$	80.00	$	122.50
March 2013		45,600	$	80.00	$	122.50
April 2013		45,500	$	80.00	$	122.50
May 2013		45,500	$	80.00	$	122.50
June 2013		45,500	$	80.00	$	122.50
July 2013		44,500	$	80.00	$	122.50
August 2013		44,500	$	80.00	$	122.50
September 2013		44,500	$	80.00	$	122.50
October 2013		43,400	$	80.00	$	122.50
November 2013		43,400	$	80.00	$	122.50
December 2013		43,400	$	80.00	$	122.50
January 2014		42,500	$	80.00	$	122.50
February 2014		42,500	$	80.00	$	122.50
March 2014		42,500	$	80.00	$	122.50
April 2014		41,500	$	80.00	$	122.50
May 2014		41,500	$	80.00	$	122.50
June 2014		41,500	$	80.00	$	122.50
July 2014		40,600	$	80.00	$	122.50
August 2014		40,600	$	80.00	$	122.50
September 2014		40,600	$	80.00	$	122.50
October 2014		39,700	$	80.00	$	122.50
November 2014		39,700	$	80.00	$	122.50
December 2014		39,700	$	80.00	$	122.50

The amounts received by Whiting from the hedge contract counterparty upon settlements of the hedge contracts will reduce production and development costs attributable 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 use of such excess amounts to offset operating expenses will be deferred, with interest accruing on such amounts at the prevailing money

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market rate, until the next quarterly period where the current and deferred hedge payments and other non-production revenue are less than the applicable production and development costs. 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 and in turn attributable to the underlying properties. 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 mainly 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 February 22, 2012:

	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
Rocky Mountains		37,163		14,650		—		—		37,163		14,650
Permian Basin		34,683		25,426		1,200		227		35,883		25,653
Gulf Coast		11,189		4,434		470		164		11,659		4,598
Mid-Continent		3,623		2,135		—		—		3,623		2,135
Total		86,658		46,645		1,670		391		88,328		47,036

The following is a summary of the producing wells on the underlying properties as of December 31, 2011:

	Operated Wells				Non-Operated Wells				Total
	Gross		Net		Gross		Net		Gross		Net
Oil		294		264.2		926		92.1		1,220		356.3
Natural gas		34		29.1		46		4.9		80		34.0
Total		328		293.3		972		97.0		1,300		390.3

The following is a summary of the number of developmental wells drilled on the underlying properties during the last three years. A dry well is an exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. A productive well is an exploratory, development or extension well that is not a dry well. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves found. Whiting did not drill any exploratory wells on the underlying properties during the periods presented.

	Year Ended December 31,
	2009				2010				2011
	Gross		Net		Gross		Net		Gross		Net
Productive
Oil wells		12		4.37		10		8.07		20		4.71
Natural gas wells		2		0.04		—		—		2		0.06
Dry		—		—		—		—		—		—
Total		14		4.41		10		8.07		22		4.77

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During the year ended December 31, 2011, Whiting drilled, completed and commenced production with respect to 22 wells on the underlying properties.

OIL AND NATURAL GAS SALES

The following table shows the sales volumes, average sales prices per Bbl of oil and Mcf of natural gas produced and the production costs per BOE for the underlying properties. 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.

	Year Ended December 31,
	2009		2010		2011
Net sales volumes:
Oil production (MBbl)(1)		1,572		1,459		1,382
Natural gas production (MMcf)		4,318		3,335		2,717
Total production (MBOE)		2,292		2,015		1,834
Average daily production (MBOE/d)		6.3		5.5		5.0
Keystone, South field sales volumes(2):
Oil production (MBbl)(1)		178		154		159
Natural gas production (MMcf)		843		758		596
Total production (MBOE)		318		281		258
Rangely field sales volumes(2):
Oil production (MBbl)(1)		208		195		187
Natural gas production (MMcf)		-		-		-
Total production (MBOE)		208		195		187
Average sales prices:
Oil (per Bbl)(1)	$	54.60	$	71.74	$	87.47
Natural gas (per Mcf)	$	4.58	$	5.71	$	6.22
Production costs (per BOE)(3)	$	13.58	$	16.51	$	19.41

(1) Includes natural gas liquids.

(2) The Keystone, South and Rangely fields were the only fields that contained 15% or more of the total proved reserve volumes of the underlying properties as of December 31, 2009, 2010 and 2011.

(3) Production costs reported above exclude from lease operating expenses ad valorem taxes of $4.0 million ($1.72/BOE), $4.1 million ($2.05/BOE) and $3.8 million ($2.05/BOE) for the years ended December 31, 2009, 2010 and 2011, respectively.

DELIVERY COMMITMENTS

Neither the trust nor the underlying properties are committed to deliver fixed quantities of oil or natural gas in the future under existing contracts or agreements.

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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, 2011 and the average daily net production attributable to the net profits interest for the three months ended December 31, 2011.

			Estimated Proved Reserves As of December 31, 2011																	Three Months Ended December 31, 2011 Average Daily Net Production (BOE/d)
Region/Field	State		Oil(1) (MBbl)		Natural Gas (MMcf)		Total (MBOE)(2)		% Oil			% of Total Reserves			Pre-Tax PV10% Value(2)(3) (In Millions)		% of Total Pre-Tax PV10% Value
Rocky Mountains (14 Fields)
Rangely		CO		1,405		—		1,405		100.0	%		13.2	%	$	36.7		11.4	%		464
Garland		WY		1,145		370		1,207		94.9	%		11.4	%		41.2		12.7	%		486
Cedar Hills		ND		399		14		401		99.4	%		3.8	%		18.5		5.7	%		231
Torchlight		WY		635		—		635		100.0	%		6.0	%		16.5		5.1	%		204
Other				769		331		825		93.3	%		7.8	%		33.3		10.3	%		349
Rocky Mountains Total				4,353		715		4,473		97.3	%		42.2	%	$	146.2		45.2	%		1,734
Permian Basin (17 Fields)
Keystone, South		TX		846		4,052		1,521		55.6	%		14.3	%	$	42.7		13.2	%		623
Martin		TX		242		1,331		463		52.1	%		4.4	%		12.3		3.8	%		189
DEB		TX		440		68		452		97.5	%		4.3	%		15.6		4.8	%		332
Signal Peak		TX		158		3,002		659		24.0	%		6.2	%		13.4		4.2	%		315
Sable		TX		373		—		373		100.0	%		3.5	%		11.3		3.5	%		130
Other				810		1,572		1,072		75.6	%		10.1	%		32.8		10.1	%		402
Permian Basin Total				2,869		10,025		4,540		63.2	%		42.8	%	$	128.1		39.6	%		1,991
Gulf Coast (8 Fields)
Lake Como		MS		425		401		492		86.4	%		4.6	%	$	19.4		6.0	%		226
Other				275		2,496		690		39.8	%		6.5	%		16.2		5.0	%		391
Gulf Coast Total				700		2,897		1,182		59.2	%		11.1	%	$	35.6		11.0	%		617
Mid-Continent (10 Fields)
Wesson		AR		287		8		288		99.6	%		2.7	%	$	10.9		3.3	%		78
Other				69		337		125		55.0	%		1.2	%		2.8		0.9	%		69
Mid-Continent Total				356		345		413		86.1	%		3.9	%	$	13.7		4.2	%		147
Total (49 fields)				8,278		13,982		10,608		78.0	%		100.0	%	$	323.6		100.0	%		4,489

(1) Includes natural gas liquids.

(2) The amounts in the table reflect the trust’s 90% net profits interest in the reserves attributable to the underlying properties during the term of the trust. Proved reserves reflected in the table above for the net profits interest are derived from oil and natural gas prices calculated using an average of the first-day-of-the month prices for each month within the 12 months ended December 31, 2011, pursuant to current SEC and FASB guidelines, which equal $96.19 per Bbl of oil and $4.12 per MMBtu of natural gas adjusted for a field transportation, quality and basis differential of $8.94 per Bbl of oil and a premium of $1.88 per Mcf of natural gas, resulting in average field adjusted prices of $87.25 per Bbl of oil (which includes the effects of natural gas liquids) and $6.00 per Mcf of natural gas. The average first-day-of-the month price for the 12 months ended December 31, 2011 applied to natural gas liquids was $69.61 per Bbl.

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(3) Pre-tax PV10% value is 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, 2011, 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 56% of these properties were operated by Whiting. Based on production for the three months ended December 31, 2011 attributable to the net profits interest of 4,489 BOE/d, approximately 75% was oil and natural gas liquids and 25% was natural gas. The net profits interest excludes Whiting’s interests in the Bakken and Three Forks formations in all regions. See “— Capital expenditure activities” for a summary of the anticipated development plans relating to the underlying properties and the capital expected to be required to conduct such development activities.

Rocky Mountains Region.    The underlying properties in the Rocky Mountains region are located in Colorado, Wyoming, North Dakota and Montana. These properties consist of 14 fields of which Whiting operates wells in five of these fields. Whiting operates approximately 18% of these properties based on average daily net production attributable to the net profits interest of 1,734 BOE/d for the three months ended December 31, 2011 from 832 gross (109.2 net) wells. The net profits interest excludes Whiting’s interest in the Bakken and Three Forks formations. The following table summarizes Whiting’s interests in the major fields in this region.

Field

No. of Wells Operated / Non-Operated

Operator

State

County

Productive Zones

Gross / Net Acres

Average Working Interest

Average Net Revenue Interest

Rangely

8/372

Chevron Corporation, Whiting

CO

Rio Blanco

Weber Sand

6,567/2,210

4.6

%

3.9

%

Garland

0/122

Marathon Oil Corporation

WY

Big Horn

Madison, Tensleep

0/0

19.7

%

17.2

%

Cedar Hills

0/242

Continental Resources Inc., ConocoPhillips

ND

Bowman

Red River

4,616/922

1.1

%

1.0

%

Torchlight

29/0

Whiting

WY

Big Horn

Madison, Tensleep

1,085/1,085

100.0

%

79.4

%

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Permian Basin Region.    The underlying properties in the Permian Basin region are located in Texas and New Mexico. These properties consist of 17 fields of which Whiting operates wells in 12 of these fields. Whiting operates approximately 86% of these properties based on average daily net production attributable to the net profits interest of 1,991 BOE/d for the three months ended December 31, 2011 from 372 gross (233.4 net) wells. The following table summarizes Whiting’s interests in the major fields in this region.

Field

No. of Wells Operated / Non-Operated

Operator

State

County

Productive Zones

Gross / Net Acres

Average Working Interest

Average Net Revenue Interest

Keystone, South

67/1

Whiting

TX

Winkler

Clear Fork, Wichita Albany, Ellenberger

8,940/8,720

99.0

%

79.9

%

Martin

21/0

Whiting

TX

Andrews

Clear Fork, Wichita Albany

459/459

100.0

%

83.3

%

DEB

9/0

Whiting

TX

Gaines

Wolfcamp

738/738

100.0

%

81.3

%

Signal Peak

76/29

Whiting and Southwest Royalties, Inc.

TX

Howard

Wolfcamp

14,573/8,794

65.8

%

52.0

%

Sable

29/0

Whiting

TX

Yoakum

San Andres

2,112/2,112

100.0

%

83.3

%

Gulf Coast Region.    The underlying properties in the Gulf Coast region are located in Texas and Mississippi. These properties consist of eight onshore fields of which Whiting operates wells in four of these fields. Whiting operates approximately 91% of these properties based on average daily net production attributable to the net profits interest of 617 BOE/d for the three months ended December 31, 2011 from 50 gross (18.7 net) wells. The following table summarizes Whiting’s interest in the major field in this region.

Field

No. of Wells Operated / Non-Operated

Operator

State

County

Productive Zones

Gross / Net Acres

Average Working Interest

Average Net Revenue Interest

Lake Como

4/0

Whiting

MS

Jasper

Smackover

1,516/890

70.4

%

55.9

%

Mid-Continent Region.    The underlying properties in the Mid-Continent region are located in Michigan, Arkansas, Oklahoma and Texas. These properties consist of 10 fields of which Whiting operates wells in five of these fields. Whiting operates approximately 85% of these properties based on average daily net production attributable to the net profits interest of 147 BOE/d for the three months ended December 31, 2011 from 46 gross (29.1 net) wells. The following table summarizes Whiting’s interest in the major field in this region.

Field

No. of Wells Operated / Non-Operated

Operator

State

County

Productive Zones

Gross / Net Acres

Average Working Interest

Average Net Revenue Interest

Wesson

27/0

Whiting

AR

Quachita

Hogg Sand

1,191/538

71.1

%

61.0

%

CAPITAL EXPENDITURE ACTIVITIES

The primary goals of the planned capital expenditures relative to the underlying properties are to convert proved undeveloped reserves and developed non-producing properties to producing properties and to make the capital expenditures with a goal of mitigating the natural decline in production from producing properties. The underlying properties have a capital expenditure budget per the reserve report of $25.8 million estimated to be

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spent over 10 years. No assurance can be given, however, that any such expenditures will result in production in commercially paying amounts, if any, or that the characteristics of any newly developed well will match the characteristics of existing wells on the underlying properties or the operator’s historical drilling success rate. With respect to the underlying properties, Whiting expects, but is not obligated, to implement the development strategies described below relative to each of the following regions. With respect to fields for which Whiting is not the operator, Whiting will have no control over the timing or amount of capital expenditures relative to such fields. Please read “Risk factors — Whiting has limited control over activities on certain of the underlying properties that Whiting does not operate, which could reduce production from the underlying properties, increase capital expenditures and reduce cash available for distribution to trust unitholders.” Information relating to planned capital expenditures and development activities relating to fields for which Whiting is not the operator represent Whiting’s most recent understanding of the planned expenditures and activities of the operator thereof.

During each twelve-month period beginning on the later to occur of (1) December 31, 2017 and (2) the time when 8.24 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 7.41 MMBOE in respect of the net profits interest) (in either case, the “capital expenditure limitation date”), the sum of the capital expenditures and amounts reserved for approved capital expenditure projects for such twelve-month period may not exceed the average annual capital expenditure amount. The “average annual capital expenditure amount” means the quotient of (x) the sum of the capital expenditures and amounts reserved for approved capital expenditure projects with respect to the three twelve-month periods ending on the capital expenditure limitation date, divided by (y) three. Commencing on the capital expenditure limitation date, and each anniversary of the capital expenditure limitation date thereafter, the average annual capital expenditure amount will be increased by 2.5% to account for expected increased costs due to inflation.

Region/Field/Description	2012 – 2021 Planned Capital Expenditures (in millions)		Gross Wells		Net Wells
Rocky Mountains
Rangely — CO2 and maintenance capital	$	19.4		—		—
Rangely — drill wells		1.2		12		0.6
Rocky Mountains Total	$	20.6		12		0.6
Permian Basin
Keystone, South — recompletions	$	1.7		3		3.0
Sand Tank — drill wells		1.6		2		0.4
Parkway — drill well		1.5		1		0.4
Santo Nino — drill well(1)		—		1		0.2
Permian Basin Total	$	4.8		7		4.0
Gulf Coast
Agua Dulce — recompletions	$	0.4		2		2.0
Mid-Continent	$	—		—		—
Total	$	25.8		21		6.6

(1) Well substantially completed in 2011 with no capital expenditures to be incurred in 2012.

Rocky Mountains Region.    Capital expenditures for the underlying properties in the Rocky Mountains region have averaged $3.8 million per year over the three year period ending December 31, 2011. The Rangely field, operated by Chevron Corporation, is located in Rio Blanco County, Colorado. This field was discovered in 1931 with development drilling commencing in 1943. The field is currently producing under the tertiary recovery process of CO₂ injection. The underlying properties include a 4.6% working interest in the Rangely Weber Sand Unit. Capital is expended each year to purchase CO₂ for injection in the field and there has been capital expended drilling additional wells in the field to optimize recovery. According to information provided at the latest

59

working interest owners meeting held on November 2, 2011, the 2012 capital expenditure budget is $68.4 million gross, which equates to approximately $3.2 million allocated to the underlying properties, and is comprised of $26.4 million for 2012 development activities, $28.2 million for plant and equipment expenditures and $13.8 million for CO₂ purchases. After 2012, Whiting estimates that the 2012 budgeted level of plant and equipment expenditures and CO₂ purchases, which total $42.0 million gross, or approximately $1.9 million allocated to the underlying properties, will continue through 2021, the projected life of the net profits interest. These capital expenditures are included in the reserve report. The capital expenditures for development activities of $26.4 million gross, or approximately $1.2 million allocated to the underlying properties, scheduled for 2012 to include 12 development wells to further develop the field and the drilling of one replacement injector well. A subsequent communication from Chevron indicated 2 of the 12 development wells may be scheduled for 2013. The expenditures for the replacement well are included in the proved developed producing category expenditures and expenditures for the 12 development wells are reflected in the proved undeveloped reserve category in the reserve report. No additional development capital expenditures are reflected in the reserve report. Although Whiting is not aware of any other development plans by Chevron or other operators of the underlying properties in this region, these operators may propose capital expenditures in the future. Additionally, although Whiting has not identified any future capital expenditures for the Whiting operated fields at this time, further study or offsetting drilling activity may result in capital expenditures in the future.

Permian Basin Region.    Capital expenditures for the underlying properties in the Permian Basin region have averaged $16.3 million per year over the three year period ending December 31, 2011. Whiting operates the Keystone, South field in Winkler County, Texas, which produces from several different zones including the Clear Fork, Wichita Albany and Ellenberger zones at depths from 6,500 to 9,200 feet. Whiting plans to recomplete three wells from the currently completed zone to another zone expected to be productive in the wellbore. These three recompletions are scheduled to be performed in 2013 and 2014 when the currently producing zones reach their economic limit. The capital expenditures necessary to perform these recompletions, which are included as proved developed non-producing reserves in the reserve report, are estimated at approximately $1.7 million allocated to the underlying properties. Although Whiting has not identified future capital expenditures for any other operated fields in the Permian Basin at this time, further study or offsetting development activity may result in substantial additional capital expenditures in the future.

Whiting owns non-operated working interests in the Parkway, Sand Hills and Santo Nino fields located in Eddy County, New Mexico. Mewbourne Oil Company, the operator, is developing these fields with horizontal wellbores in the Bone Spring formation at a depth of 8,000 feet. One of these wells was recently drilled and completed in December 2011. This well was included in the proved developed non-producing reserve category in the reserve report because there was no production data available at the time of the reserve report. All capital was expended prior to the January 1, 2012 effective date of the trust. Mewbourne spud one well in December 2011 and has proposed an additional two wells to be spud in May 2012 and July 2012. These three wells are in the proved undeveloped reserve category in the reserve report with an estimated capital expenditure of approximately $3.1 million allocated to the underlying properties. Although Whiting is not aware of any other development plans by Mewbourne or other operators of the underlying properties in this region, these operators may propose capital expenditures in the future.

Gulf Coast Region.    Capital expenditures for the underlying properties in the Gulf Coast region have averaged $1.7 million per year over the three year period ending December 31, 2011. Whiting operates the Agua Dulce field in Nueces County, Texas, which produces from several different Vicksburg zones at depths from 9,000 to 10,000 feet. Whiting plans to recomplete two wells from the currently completed depleted zone to another zone expected to be productive in the wellbore. These two recompletions are scheduled to be performed in 2013 at an estimated capital expenditure of approximately $0.4 million allocated to the underlying properties. Although Whiting has not identified any future capital expenditures for any other operated fields at this time, further study or offsetting development activity may result in additional capital expenditures in the future. Additionally, although Whiting is not aware of any development plans by other operators of the underlying properties in this region, these operators may propose capital expenditures in the future.

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Mid-Continent Region.    Capital expenditures for the underlying properties in the Mid-Continent region have averaged $0.1 million per year over the three year period ending December 31, 2011. Although Whiting has not identified any future capital expenditures for the Whiting operated fields at this time, further study or offsetting drilling activity may result in capital expenditures in the future. Additionally, although Whiting is not aware of any development plans by other operators of the underlying properties in this region, these operators may propose capital expenditures in the future.

The trust is not directly obligated to pay any portion of any development expenditures made with respect to the underlying properties; however, development expenditures made by Whiting with respect to the underlying properties will be included among the production and development costs that, together with the reserves established by Whiting for similar future costs, will be deducted from the gross proceeds in calculating cash distributions attributable to the net profits interest. As a result, the trust will indirectly bear a 90% share of any development expenditures made with respect to the underlying properties (subject to certain limitations near the end of the term of the net profits interest, as described below). Accordingly, higher or lower development expenditures will, in general, directly decrease or increase, respectively, the cash received by the trust. In making development expenditure determinations, Whiting will attempt to balance the impact of the development expenditures on current cash distributions to the trust unitholders with the longer term benefits of increased oil and natural gas production expected to result from the development expenditure. In addition, Whiting may establish a capital reserve of up to a maximum of $2.0 million in the aggregate at any given time for future development, maintenance or operating expenses.

Whiting, as the designated operator of 56% of the underlying properties based on the pre-tax PV10% value contained in the reserve report, is entitled to make all determinations related to development expenditures with respect to the underlying properties, and there are no limitations on the amount of development expenditures that Whiting may incur with respect to the underlying properties, except as described below. Whiting is required under the applicable net profits interest conveyance 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. As the trust unitholders would not be expected to fully realize the benefits of development expenditures made with respect to the underlying properties which occur near the end of the term of the net profits interest, during each twelve-month period beginning on the later to occur of (1) December 31, 2017 and (2) the time when 8.24 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 7.41 MMBOE in respect of the net profits interest), the trust’s obligation for development expenditures that may be included among the costs that will be taken into account in calculating net proceeds attributable to the net profits interest will be limited to the average annual development expenditures incurred by Whiting during the preceding three years, as increased by 2.5% to account for expected increased costs due to inflation. See “Computation of net proceeds — Net profits interest.”

RESERVE REPORT

Technologies.    The underlying properties are predominantly mature fields with limited remaining development opportunities identified at this time. Of the total proved reserve volumes estimated for the underlying properties during the estimated term of the net profits interest, 96.4% are classified as proved developed producing reserves. These producing reserve estimates were prepared using production performance decline curve analyses, supplemented by analogy performance as appropriate. The total reserves classified as either proved developed non-producing or proved undeveloped comprise only 3.6% of the proved reserves. These reserve estimates were based on performance of analog wells completed in the targeted formation in the same field. In a few cases, the analog data was supplemented by volumetric recovery calculations.

Preparation of reserves estimates.    Whiting believes it maintains adequate and effective internal controls over the reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are comprised of technical information, financial data,

61

ownership interests and production data. All field and reservoir technical information, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land personnel to discuss field performance. Current revenue and expense information is obtained from Whiting’s accounting records, which are subject to internal controls that are assessed for effectiveness by Whiting’s management. All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Whiting’s current ownership in mineral interests and well production data are also subject to Whiting’s internal controls, and they are incorporated in the reserve database as well and verified to ensure their accuracy and completeness. Once the reserve database has been entirely updated with current information and all relevant technical support material has been assembled, the Trust’s independent engineering firm Cawley, Gillespie & Associates, Inc. (“CG&A”) meets with Whiting’s technical personnel in Whiting’s Denver and Midland offices to review field performance. Following these reviews the reserve database is furnished to CG&A so that they can prepare their independent reserve estimates and final report. Access to Whiting’s reserve database is restricted to specific members of the reservoir engineering department.

CG&A is a Texas Registered Engineering Firm. The primary contact at CG&A is Mr. Robert Ravnaas, Executive Vice President. Mr. Ravnaas is a State of Texas Licensed Professional Engineer. See Appendix A and Exhibit 99 of this prospectus for the Report of Cawley, Gillespie & Associates, Inc. and further information regarding the professional qualifications of Mr. Ravnaas.

Whiting’s Vice President of Reservoir Engineering and Acquisitions is responsible for overseeing the preparation of the reserves estimates. He has over 38 years of experience, the majority of which has involved reservoir engineering and reserve estimation, holds a Bachelor’s Degree in Petroleum Engineering from the University of Wyoming, holds an MBA from the University of Denver and is a registered Professional Engineer. He has also served on the national Board of Directors of the Society of Petroleum Evaluation Engineers.

The standardized measures for the underlying properties presented below were prepared using assumptions required by the SEC. Except to the extent otherwise described below, these assumptions include the use of oil and natural gas prices calculated using an average of the first-day-of-the month price for each month within the 12 months ended December 31, 2011, pursuant to current SEC and FASB guidelines, which equal $96.19 per Bbl of oil and $4.12 per MMBtu of natural gas adjusted for a field transportation, quality and basis differential of $8.94 per Bbl of oil, and a premium of $1.88 per Mcf of natural gas, resulting in average field adjusted prices of $87.25 per Bbl of oil (which includes the effects of natural gas liquids) and $6.00 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, 2011. The average first-day-of-the month price for the 12 months ended December 31, 2011 applied to natural gas liquids was $69.61 per Bbl. Because oil and natural gas prices are influenced by many factors, use of the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from January 1, 2011 through December 1, 2011, 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 “U.S. federal income tax consequences” for more information.

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Proved reserves.    The following table sets forth, as of December 31, 2011, 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.

	As of December 31, 2011
	Underlying Properties(1)		Underlying Properties (attributable to the net profits interest)(2)
Proved reserves:
Oil and natural gas liquids (MBbls)		14,687		8,278
Natural gas (MMcf)		21,554		13,982
Oil equivalents (MBOE)		18,280		10,608
Pre-tax PV10% value (in thousands)(3)	$	408,503	$	323,597
Standardized measure (in thousands)(3)	$	408,503	$	323,597

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

(2) Reflects 90% of the volumes, pre-tax PV10% value and standardized measure 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.

(3) 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 measures of the underlying properties and the underlying properties attributable to the net profits interest equal their corresponding pre-tax PV10% values, which totaled $408.5 million and $323.6 million, respectively, as of December 31, 2011.

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.

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

	Oil (MBbl)			Natural Gas (MMcf)			Total (MBOE)
Balance at January 1, 2009		12,767			25,357			16,994
Revisions to previous estimates		6,595			13,983			8,925
Extensions and discoveries		—			4			1
Production		(1,572	)		(4,318	)		(2,292	)
Balance, December 31, 2009		17,790			35,026			23,628
Revisions to previous estimates		(572	)		(4,275	)		(1,285	)
Extensions and discoveries		10			15			13
Production		(1,459	)		(3,335	)		(2,015	)
Balance, December 31, 2010		15,769			27,431			20,341
Revisions to previous estimates		38			(3,768	)		(590	)
Extensions and discoveries		262			608			363
Production		(1,382	)		(2,717	)		(1,834	)
Balance at December 31, 2011		14,687			21,554			18,280
Proved developed reserves:
Balance at December 31, 2008		11,809			21,972			15,471
Balance at December 31, 2009		16,031			26,779			20,494
Balance at December 31, 2010		14,881			23,824			18,852
Balance at December 31, 2011		14,528			21,284			18,076
Proved undeveloped reserves:
Balance at December 31, 2008		959			3,386			1,523
Balance at December 31, 2009		1,759			8,247			3,133
Balance at December 31, 2010		888			3,607			1,489
Balance at December 31, 2011		159			270			204

Proved reserves.    Estimates of proved developed and undeveloped reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

In 2011, revisions to previous estimates decreased proved reserves by a net amount of 590 MBOE. Included in these revisions were 38 MBbl of upward adjustments to crude oil reserves and 3.8 Bcf of downward adjustments to natural gas reserves. The reduction in natural gas reserves was primarily attributable to the removal of five Permian Basin oil and gas wells from the proved undeveloped reserve category. The continued environment of low natural gas prices affected the economic viability of these proved undeveloped locations. Whiting therefore no longer planned to drill these wells within five years of their initial inclusion as proved undeveloped reserves, and they were removed from the proved undeveloped reserve category accordingly, as required by SEC rules on oil and gas reserves. The resulting negative oil revision associated with the removal of these five wells was more than offset by the upward adjustment in oil reserves that was attributable to higher crude oil prices incorporated into reserves estimates at December 31, 2011 as compared to December 31, 2010. This increase in oil price used in year-end reserve estimates from $79.43 per Bbl at December 31, 2010 to $96.19 per Bbl at December 31, 2011 extended the economic lives of many oil wells.

In 2010, revisions to previous estimates decreased proved reserves by a net amount of 1,285 MBOE. Included in these revisions were 572 MBbl of downward adjustments to crude oil reserves and 4.3 Bcf of downward adjustments to natural gas reserves. Both of these reserve reductions were primarily attributable to a negative revision of the proved reserves associated with the Clearfork waterflood project in the Keystone, South field. Oil response to water injection was less than expected due to reservoir continuity and conformance issues.

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In 2009, revisions to previous estimates increased proved reserves by a net amount of 8,925 MBOE. Included in these revisions were 14.0 Bcf of upward adjustments to natural gas reserves and 6,594 MBbl of upward adjustment to crude oil reserves. These increases were mainly due to higher oil prices of $61.18 per Bbl of oil in reserve estimates at December 31, 2009, as compared to $44.60 per Bbl of oil at December 31, 2008. This increase in oil price extended the economic lives of many oil wells, which increased the estimate of proved oil and the associated gas reserves.

Proved undeveloped reserves.    Proved undeveloped reserves decreased from 1,489 MBOE to 204 MBOE at December 31, 2011. This reduction of 1,285 MBOE was due primarily to Whiting’s decision not to drill five oil and gas wells in the Permian Basin. The continued environment of low natural gas prices affected the economic viability of these proved undeveloped locations. Whiting therefore no longer planned to drill these wells within five years of their initial inclusion as proved undeveloped reserves, and they were removed from the proved undeveloped reserve category accordingly. In addition, proved undeveloped reserves were reduced by an estimated 450 MBOE due to the drilling of 11 proved undeveloped well locations in the Rangely Weber, North Vacuum and Keystone, South fields. These reserves were promoted to the proved developed producing reserve category as of December 31, 2011. Approximately $6.0 million in capital expenditures, or $13.33 per BOE, was incurred to drill and bring these wells on production. All proved undeveloped reserve quantities reflected in the reserve report were expected to be developed within five years as of the dates they have been disclosed as proved undeveloped reserves.

ABANDONMENT OF UNDERLYING PROPERTIES

Any operators of the underlying properties, including 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 the potential conflict of interest between Whiting and the trust in determining whether a well is capable of producing in commercially paying quantities, Whiting has agreed to operate the underlying properties as a reasonably prudent operator in the same manner that it would operate if these properties were not burdened by the net profits interest and Whiting has agreed to use commercially reasonable efforts to cause the other operators to operate these properties in the same manner. However, Whiting’s ability to cause other operators to take certain actions is limited. For the years ended December 31, 2009, 2010 and 2011, Whiting plugged and abandoned 11, 15 and 11 wells, respectively, with respect to the underlying properties based on its determination that such wells were no longer economic to operate.

HYDRAULIC FRACTURING

There are a total of 15 proved undeveloped drilling locations and six proved developed non-producing wells identified on the underlying properties. Of the 15 anticipated proved undeveloped drilling locations, 12 are located in the Rangely Field in Western Colorado and three are located in the Delaware Basin of Southeast New Mexico. Hydraulic fracture stimulations are expected to be utilized for completion of these wells. It is anticipated that hydraulic fracture stimulations will be utilized for all six of the proved developed non-producing wells, of which four are located in the Permian Basin of West Texas and two are along the Texas Gulf Coast.

The 12 proved undeveloped locations are down spacing opportunities on acreage that is held by production. The three proved undeveloped New Mexico wells, which include two at Sand Tank field and one at Parkway field operated by Mewbourne will be drilled on spacing units of 160 gross acres per well at Sand Tank and Parkway fields (126 net acres total). All six proved developed non-producing projects will take place in existing wells on acreage already earned and held by production.

Reserves associated with the 21 hydraulic fracture treatments total 0.4 MMBOE or 3.6% of the total reserves attributable to the underlying properties.

Whiting is not aware of any environmental issues, incidents or citations related to hydraulic fracturing on any of the underlying properties. While Whiting does not have insurance policies in effect that are intended to

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provide coverage for losses solely related to hydraulic fracturing operations, Whiting does have general liability and excess liability insurance policies that Whiting believes would cover third party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

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 liquids 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 liquids production from the underlying properties will be determined based on the same price that Whiting receives for oil, natural gas and natural gas liquids 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 2009, sales to Chevron USA, ConocoPhillips, Plains Marketing LP and Marathon Oil Corporation accounted for 13%, 13%, 11% and 11%, respectively, of total oil and natural gas sales related to the underlying properties. During 2010, sales to Plains Marketing LP, Chevron USA, ConocoPhillips and Marathon Oil Corporation accounted for 14%, 13%, 13%, and 11%, respectively, of total oil and natural gas sales related to the underlying properties. During 2011, sales to Plains Marketing LP, Chevron USA, ConocoPhillips and Marathon Oil Corporation accounted for 16%, 14%, 13% and 11%, respectively, of total oil and gas sales related to the underlying properties. Whiting believes that the loss of any 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 any of their largest purchasers, several entities could purchase crude oil and natural gas produced from the underlying properties with little or no interruption.

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;

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

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

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

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

At the time of its acquisitions of the underlying properties, Whiting undertook a title examination of these properties. As such, Whiting believes that its title to the underlying properties is, and the trust’s title to the net profits interest will be, good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions as are not so material to detract substantially from the use or value of such properties or royalty interests. Please see “Risk factors — The trust units may lose value as a result of title deficiencies with respect to the underlying 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 Colorado, Michigan, Mississippi, Montana, North Dakota, New Mexico, Oklahoma, Texas and Wyoming, 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 net profits interest, 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.

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

ENVIRONMENTAL MATTERS AND REGULATION

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

• require the acquisition of a permit for drilling and other regulated activities;

• 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 statutes 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, rules 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 well construction, drilling, water management or completion activities or 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 more significant 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, as amended, (“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 EPA the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. In its operations at the underlying properties, Whiting generates solid and hazardous wastes that are subject to RCRA and comparable state laws. 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. In September 2010, the Natural Resources Defense Council filed a petition with the EPA, requesting them to reconsider the RCRA exemption for exploration, production and development wastes but, to date, the agency has not taken any action on the petition. Any such change in the current RCRA exemption and comparable state laws, 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.

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Comprehensive Environmental Response, Compensation and Liability Act.    The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“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. While Whiting generates materials in the course of its operations of the underlying properties that may be regulated as hazardous substances, Whiting has not been notified that it has been named as a potentially responsible party at or with respect to any Superfund sites. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

The underlying properties may have been used for oil and natural gas exploration and production for many years. Although Whiting believes that it has utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties, or on or under other locations, including off-site locations, where such substances have been taken for recycling or 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, perform remedial plugging or pit closure operations to prevent future contamination or to pay some or all of the costs of any such action.

Water discharges.    The Federal Water Pollution Control Act, or the Clean Water Act, as amended (the “CWA”), 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 the 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 CWA 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 CWA and analogous state laws and regulations.

Hydraulic fracturing.    Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. Hydraulic fracturing has been utilized in the completion of wells drilled at the underlying properties and Whiting expects it will also be used in the future. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA recently took the position that hydraulic fracturing operations using diesel are subject to regulation under the Underground Injection Control program of the Safe Water Drinking Act as Class II wells and has commenced drafting guidance for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel. Industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with initial results of the study anticipated to be available by late 2012 and final results by 2014. Moreover, the EPA recently announced in October 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. Other federal agencies are also examining hydraulic fracturing, including the DOE, the U.S. Government Accountability Office and the White House Council for Environmental Quality. The U.S. Department of the Interior is also considering

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regulation of hydraulic fracturing activities on public lands. In addition, legislation called the FRAC Act has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. For example, on June 17, 2011, Texas enacted a law that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production) and the public. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater. In addition, if hydraulic fracturing is regulated at the federal level, Whiting’s fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Further, at least three local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could make it more difficult or costly for Whiting to perform hydraulic fracturing activities. Moreover, Whiting believes that enactment of legislation regulating hydraulic fracturing at the federal level may have a material adverse effect on its business.

Global warming and climate change.    On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public heath and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. Based on these findings, the EPA has begun adopting and implementing regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one rule that limits emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Further, facilities required to obtain PSD permits for their GHG emissions are required to reduce those emissions consistent with guidance for determining “best available control technology” standards for GHGs, which guidance was published by the EPA in November 2010. Also in November 2010, the EPA expanded its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis with reporting beginning in 2012 for emissions occurring in 2011.

In addition, both houses of Congress have considered legislation to reduce emissions of GHGs, and many states have already taken legal measures to reduce emissions of GHGs, primarily through the development of GHG inventories, greenhouse gas permitting and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. In the absence of new legislation, the EPA is issuing new regulations that limit emissions of GHGs associated with our operations which will require us to incur costs to inventory and reduce emissions of GHGs associated with our operations and could adversely affect demand for the oil and natural gas that Whiting produces. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events.

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Air emissions.    The federal Clean Air Act, as amended, 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, including Whiting, may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining pre-construction and 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. For example, on July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. Among other things, these standards would require the application of reduced emission completion techniques for completion of newly drilled and fractured wells in addition to existing wells that are refractured. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by April 3, 2012. If finalized, these rules could require a number of modifications to operations at the underlying properties including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the 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, as amended (“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.

Endangered species considerations.    The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered and threatened species or their habitats. If endangered species are located in areas of the underlying properties where Whiting or the other underlying property operators wish to conduct seismic surveys, development activities or abandonment operations, the work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the Endangered Species Act. Under the September 9, 2011 settlement, the federal agency is required to begin issuing decisions with respect to the 250 candidate species by the end of 2011. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause operators of those underlying properties, including Whiting, to incur increased costs arising from species protection measures or could result in limitations on their exploration and production activities that could have an adverse impact on their ability to develop and produce reserves.

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.

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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 year ended December 31, 2011 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. 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 subsidiary, Whiting Oil and Gas Corporation, 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 87.9% and an average net revenue interest of approximately 69.7%. For the underlying properties where Whiting is not the operator, Whiting has an average working interest of approximately 18.0% and an average net revenue interest of approximately 13.7%.

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 liquids 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:

• 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, 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;

• all other costs and expenses, development costs and liabilities of testing, drilling, completing, recompleting, workovers, equipping, plugging back, operating and producing oil, natural gas and natural gas liquids, including allocated expenses such as labor, vehicle and travel costs and materials other than costs and expenses for certain future non-consent operations;

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• costs or charges associated with gathering, treating and processing oil, natural gas and natural gas liquids (provided, however that any proceeds attributable to treatment or processing will offset such costs or charges, if any);

• costs paid pursuant to existing operating agreements, including producing overhead charges;

• 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;

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

• amounts reserved at the option of Whiting for development expenditure projects, including well drilling, recompletion and workover costs, maintenance or operating expenses, which amounts will at no time exceed $2.0 million in the aggregate, and will be subject to the limitations described below (provided that such costs shall not be debited from gross proceeds when actually incurred).

All of the hedge payments received by Whiting from the hedge contract counterparty upon settlements of hedge contracts and certain other non-production revenues, as detailed in the conveyance, will offset the production and development costs outlined above (such production and development costs excluding the last bullet point above) in calculating the net proceeds. Plugging and abandonment liabilities relating to the underlying properties will not be deducted from the gross proceeds in determining net proceeds. If the hedge payments received by Whiting and certain other non-production revenues exceed the operating expenses during a quarterly period, the use of 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, together with other offsets to costs for the applicable quarter, are less than such expenses. If any excess amounts have not been used to offset costs at the time when the later to occur of (1) December 31, 2021, or (2) the time when the terminal production amount has been produced 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.

During each twelve-month period beginning on the later to occur of (1) December 31, 2017 and (2) the time when 8.24 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 7.41 MMBOE in respect of the net profits interest) (in either case, the “capital expenditure limitation date”), the sum of the capital expenditures and amounts reserved for approved capital expenditure projects for such twelve-month period may not exceed the average annual capital expenditure amount. The “average annual capital expenditure amount” means the quotient of (x) the sum of the capital expenditures and amounts reserved for approved capital expenditure projects with respect to the three twelve-month periods ending on the capital expenditure limitation date, divided by (y) three. Commencing on the capital expenditure limitation date, and each anniversary of the capital expenditure limitation date thereafter, the average annual capital expenditure amount will be increased by 2.5% to account for expected increased costs due to inflation.

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 $4,514 per annum for 2011 per active operated well, which totaled $1.7 million for the twelve months ending December 31, 2011 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.

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

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

ADDITIONAL PROVISIONS

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

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

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

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

The trustee is not obligated to return any cash received from the net profits interest. Any overpayments made to the trust by Whiting due to adjustments to prior calculations of net proceeds or otherwise will reduce future amounts payable to the trust until Whiting recovers the overpayments plus interest at the prevailing money market rate. 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 sell 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, 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 $1.0 million. 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.

For the underlying properties for which it is the designated operator, 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 or any other operator 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, or to use commercially reasonable efforts to cause the operators of the underlying properties 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 will be 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 subsidiary, Whiting Oil and Gas Corporation, will convey the net profits interest to the trust in consideration for the issuance by the trust of 18,400,000 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, 2012 to trust unitholders owning trust units on May 20, 2012. 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, 2012 through the day prior to close of this offering plus the amount payable under the net profits interest for the period from the day of closing of the offering through March 31, 2012, less any general and administrative expenses and reserves of the trust.

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 deduction of trust administrative expenses. 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 liquids 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 or otherwise to engage in activities beyond those necessary for the conservation and protection of the net profits interests.

The beneficial interest in the trust is divided into 18,400,000 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 in any material respect. 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;

• causing to be prepared and filed a reserve report by or for the trust by independent reserve engineers as of December 31 of each year in accordance with criteria established by the SEC;

• 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.

The trustee may create a cash reserve to pay for future liabilities of the trust. 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 to pay liabilities of the trust. The trustee may borrow the funds from any person, including itself or its

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affiliates, but neither the trustee nor any of its affiliates has any obligation, commitment or intention to make any loan to the trust. 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 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. Whiting has agreed to provide a letter of credit in the amount of $1.0 million to the trustee to protect the trust against the risk that it does not have sufficient cash to pay liabilities.

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 may be invested in:

• accounts payable on demand;

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

• 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, 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 $1,000,000; or

• holders representing a majority of the outstanding trust units approve 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 from the underlying properties during the term of the net profits interest.

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Under certain limited circumstances, the Trustee may be required to sell all or a portion of the net profits interest without the approval of the trust unitholders. Upon dissolution of the trust, the trustee must sell the net profits interest. No trust unitholder approval is required in this event.

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

The trustee is expected to maintain a website for filings made by the trust with the SEC to the extent required to do so by the New York Stock Exchange or any other exchange on which the units may be listed.

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 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 in any material respect.

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 and other fees and expenses applicable to public companies and in connection with this offering.

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. The trust will also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual and quarterly reports to unitholders, preparation of tax information material and distribution, independent auditor fees and registrar and transfer agent fees. These trust administrative expenses are expected to be approximately $1.0 million in 2012 and annually 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 $175,000 for the trustee, which escalates annually by 2.5% starting in 2017, 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 fees and legal expenses incurred in forming the trust, in connection with this initial public offering and related matters, 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.

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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 or acts or omissions in bad faith or which constitute gross negligence. 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 reasonable reliance upon the opinion of the expert.

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

The Delaware trustee and the trustee may, jointly, from time to time supplement or amend the conveyance, the administrative services agreement and the registration rights agreement to which the trust is a party without the approval of trust unitholders in order to cure any ambiguity, to correct or supplement any provision contained therein which may be defective or inconsistent with any other provisions therein, to grant any benefit to all of the trust unitholders, or to change the name of the trust. Such supplement or amendment, however, may not adversely affect the interests of the trust unitholders in any material respect.

TERMINATION OF THE TRUST; SALE OF THE NET PROFITS INTEREST

The net profits interest will terminate on the later to occur of (1) December 31, 2021, or (2) the time when the terminal production amount has been produced and sold, 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 $2.0 million for each of two consecutive years;

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• 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 trust 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. Subject to certain exceptions, any successor must be a bank or trust company meeting certain requirements including having combined capital, surplus and undivided profits of at least $20.0 million, in the case of the Delaware trustee, and $100.0 million, 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 18,400,000 trust units outstanding upon completion of this offering. As the market price for trust units tends to be tied to recent and expected levels of cash distributions attributable to a depleting asset, over time the price will decline to zero at the termination of the trust. Please read “Risk factors — The market price for the trust units may not reflect the value of the net profits interest held by the trust and, in addition, over time will decline to zero at the termination of the trust.”

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 “U.S. 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.

TRANSFER OF TRUST UNITS

Trust unitholders may transfer their trust units in accordance with the trust agreement. The trustee will not require either the transferor or transferee to pay a service charge for any transfer of a trust unit. The trustee may require payment of any tax or other governmental charge imposed for a transfer. The trustee may treat the owner of any trust unit as shown by its records as the owner of the trust unit. The trustee will not be considered to know about any claim or demand on a trust unit by any party except the record owner. A person who acquires a trust unit after any quarterly record date will not be entitled to the distribution relating to that quarterly record date. Delaware law will govern all matters affecting the title, ownership or transfer of trust units.

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LIABILITY OF TRUST UNITHOLDERS

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

VOTING RIGHTS OF TRUST UNITHOLDERS

The trustee or trust unitholders owning at least 10% of the outstanding trust units may call meetings of trust unitholders. The trust will be responsible for all costs associated with calling a meeting of trust unitholders unless such meeting is called by the trust unitholders, in which case the trust unitholders will be responsible for all costs associated with calling such meeting of trust unitholders. Meetings must be held in such location as is designated by the trustee in the notice of such meeting. The trustee must send written notice of the time and place of the meeting and the matters to be acted upon to all of the trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of trust units outstanding must be present or represented to have a quorum. Each trust unitholder is entitled to one vote for each trust unit owned.

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

• dissolve the trust;

• remove the trustee or the Delaware trustee;

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

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

• 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 $1,000,000 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.”

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.

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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 of the cash receipts of the trust 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 18,400,000 trust units. All of the 16,000,000 trust units sold in this offering, or the 18,400,000 trust units if the underwriters exercise their over-allotment option 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 2,400,000 trust units unless the underwriters exercise their over-allotment option) will be “restricted securities” within the meaning of Rule 144 under the Securities Act and may not be sold other than through registration under the Securities Act or pursuant to an exemption from registration, subject to the restrictions on transfer contained in the lock-up agreements described below and in “Underwriting.”

LOCK-UP AGREEMENTS

In connection with this offering, Whiting has agreed, for a period of 180 days after the date of this prospectus, not to offer, sell, contract to sell or otherwise dispose of or transfer any trust units or any securities convertible into or exchangeable for trust units without the prior written consent of Raymond James & Associates, Inc., subject to specified exceptions. See “Underwriting” for a description of these lock-up arrangements. Upon the expiration of these lock-up agreements, 2,400,000 trust units, unless the underwriters exercise their over-allotment option, 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 units 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.

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REGISTRATION RIGHTS

The trust intends to enter into a registration rights agreement with Whiting in connection with Whiting’s contribution to the trust of the net profits interest. In the registration rights agreement, the trust will agree, for the benefit of Whiting and any transferee of its trust units (each, a “holder”), to register the trust units it holds. Specifically, the trust will agree:

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

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

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

• have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities;” 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 representing a majority of the then outstanding registrable trust units will have the right to require the trust to file up to three registration statements and all holders 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, which will be borne by the seller of the trust units. The registration rights agreement will automatically terminate in the event that the underwriters’ over-allotment option is exercised in full.

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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 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, 2011. See “Where you can find more information” for information relating to where you can find these documents.

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U.S. FEDERAL INCOME TAX 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.

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 for U.S. federal income tax purposes. Instead, the trust is relying on opinions of Foley & Lardner LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the trust units and the prices at which trust units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to the trust unitholders, and thus will be borne indirectly by the trust unitholders. Furthermore, the tax treatment of the trust, or of an investment in the trust, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Foley & Lardner LLP and are based on the accuracy of the representations made by Whiting and the trust.

For the reasons described below, Foley & Lardner LLP has not rendered an opinion with respect to the following specific federal income tax issues: (1) whether the trust’s quarterly convention for allocating taxable income and losses is permitted (please read “— Tax consequences of trust unit ownership — Direct taxation of trust unitholders”); and (2) the treatment of the net profits interest in the event it is not treated as a “production payment” under Section 636 of the Code or otherwise as a debt instrument for U.S. federal tax purposes, including whether or the extent to which depletion would be available to a trust unitholder with respect to the net profits interest (please read “— Tax consequences to U.S. trust unitholders — Payments of interest on the trust units”).

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;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Classification and taxation of the trust

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

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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.

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.

Direct taxation of trust unitholders

Because the trust will be treated as a grantor trust for U.S. federal income tax purposes, trust unitholders will be treated for such purposes as owning direct interests 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). Information returns will be filed as required by the widely held fixed investment trust rules, reporting to the trust unitholders all items of income, gain, loss, deduction and credit, which will be allocated based on record ownership on the quarterly record dates and must be included in the tax returns of the trust unitholders. Income, gain, loss, deduction and credits attributable to the assets of the trust will be taken into account by trust unitholders consistent with their method of accounting and without regard to the taxable year or accounting method employed by the trust.

Following the end of each quarter, the trustee will determine the amount of funds available as of the end of such quarter for distribution to the trust unitholders and will make distributions of available funds, if any, to the unitholders on or about the 60th day following the end of the quarter to the unitholders of record on the 50th day following the end of the quarter. In certain circumstances, however, a trust unitholder will not receive the distribution attributable to such income. For example, if the trustee establishes a reserve or borrows money to satisfy liabilities of the trust, income associated with the cash used to establish that reserve or to repay that loan must be reported by the trust unitholder, even though that cash is not distributed to the trust unitholder.

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. 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.

Tax rates

Under current law, the highest stated U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest stated U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest stated U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

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The recently enacted Health Care and Education Reconciliation Act of 2010 will impose a 3.8% Medicare tax on certain investment income earned by individuals and certain estates and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income would generally include interest income derived from investments such as the trust units and gain realized by a trust unitholder from a sale of trust units. In the case of an individual, the tax will be imposed on the lesser of (i) the trust unitholder’s net income from all investments, and (ii) the amount by which the trust unitholder’s modified adjusted gross income exceeds $250,000 (if the trust unitholder is married and filing jointly or a surviving spouse) or $200,000 (if the trust unitholder is not married). In the case of an estate or trust, the tax will be imposed on the lesser of (1) undistributed net investment income, or (2) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Classification of the net profits interest

Based on the reserve report and representations made by Whiting regarding the expected economic life of the underlying properties and the expected duration of the net profits interest, in the opinion of Foley & Lardner LLP, (i) the net profits interest should be treated as a “production payment” under Section 636 of the Code or otherwise as a debt instrument for U.S. federal income tax purposes and (ii) the net profits interest should therefore be treated as indebtedness subject to the Treasury Regulations applicable to contingent payment debt instruments regulations (the “CPDI regulations”). The trust has agreed to be bound by Whiting’s application of the CPDI regulations, including Whiting’s determination of the rate at which interest is deemed to accrue on such interests. Thus, each trust unitholder should be treated as making a loan on the underlying properties to Whiting in an aggregate amount generally equal to the purchase price of the trust units (less an amount equal to the distribution attributable to the period from January 1, 2012 through the day prior to the close of this offering) and proceeds payable to the trust from the sale of production from the burdened properties (from and after the day of closing of this offering) 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 and the trust will treat the net profits interest as indebtedness subject to the CPDI regulations, and by purchasing trust units, each trust unitholder will agree to be bound by Whiting’s application of the CPDI regulations, including its 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 Whiting’s determinations. No assurance can be given that the IRS will not assert that the net profits interest should be treated differently. Such different treatment could affect the amount, timing and character of income, gain or loss in respect of an investment in trust units and could require a trust unitholder to accrue interest income at a rate different than the “comparable yield” described below.

TAX CONSEQUENCES TO U.S. TRUST UNITHOLDERS

Payments of interest on the trust units

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

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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 Whiting 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.

Under the CPDI regulations, Whiting is required to establish the comparable yield for the debt instrument represented by ownership of the trust units. Whiting intends to take the position that the comparable yield for the debt instrument held by the trust is an annual rate of approximately 9.0%, compounded quarterly. The CPDI regulations require that Whiting provides to the trust, solely for determining the amount of interest accruals for U.S. federal income tax purposes, a schedule of the projected amounts of payments, which are referred 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.

Whiting’s 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 Whiting or included on previously filed tax returns by the trust unitholders.

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

For U.S. federal income tax purposes, a trust unitholder is required under the CPDI regulations to use the comparable yield and the projected payment schedule established by Whiting 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, the trust and every trust unitholder agree (in the absence of an administrative determination or judicial ruling to the contrary) to be bound by Whiting’s determination of the comparable yield and projected payment schedule.

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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 is required to 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) first 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 portion of the purchase price of the trust units attributable to the right to receive a distribution based on production from the Underlying Properties for the period commencing January 1, 2012 and ending on the day prior to the close of this offering will be treated by Whiting and the trust as a tax-free return of capital when such distribution is received.

Neither the trust nor the trust unitholders are entitled to claim depletion deductions with respect to the net profits interest.

If the net profits interest is not properly treated as a debt instrument, then the U.S. federal income tax consequences are uncertain. If the net profits interest is not treated as a production payment (and not otherwise as a debt instrument) for federal income tax purposes, the trust intends to take the position that its basis in the net profits interest is recouped in proportion to the production from the net profits interest. In that event a trust unitholder should be allowed to recoup its basis in the net profits interest, either through 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, beginning on January 1, 2013, absent new applicable legislation, a phase out of excess itemized deductions. Because of this uncertainty, Foley & Lardner LLP has not rendered an opinion with respect to this matter and 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).

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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 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 and, absent new applicable legislation, beginning on January 1, 2013, the amount of otherwise allowable itemized deductions will be reduced 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

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advisers with respect to other tax consequences of the ownership of the trust units, including the possible imposition of a 30% branch profits tax in the case of a non-U.S. trust unitholder that is classified for federal income tax purposes as a corporation.

Sale or exchange of trust units

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

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

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

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

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

Backup withholding tax and information reporting

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

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

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

• is a United States person;

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

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

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

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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 neither the property held by the trust nor the trust units are treated as debt-financed property within the meaning of Section 514(b) of the Code. In general, trust property would be debt-financed if the trust incurs debt to acquire the property or otherwise incurs or maintains a debt that would not have been incurred or maintained if the property had not been acquired and a trust unit would be debt-financed if the trust unitholder incurs debt to acquire the trust unit or otherwise incurs or maintains a debt that would not have been incurred or maintained if the trust unit had not been acquired.

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 Texas, Wyoming, North Dakota, Colorado, New Mexico, Mississippi, Arkansas, Montana, Michigan and Oklahoma. 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, other than Texas and Wyoming, the trust should be treated as a grantor trust, and a trust unitholder should be considered to own and receive such trust unitholder’s 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, Colorado, New Mexico, Mississippi, Arkansas, Montana, Michigan or Oklahoma 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 generally will not be subject to income tax by such state on the individual’s share of the trust’s income, except to the extent the trust units are employed by such trust unitholder in a trade, business, profession or occupation carried on in such state. In general, an individual trust unitholder will not be deemed to carry on a trade, business, profession or occupation in such state solely by reason of the purchase and sale of trust units for such nonresident’s own account as an investor.

An individual who is a nonresident of Colorado, New Mexico, Mississippi and Arkansas 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 and Michigan 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 New Mexico and Oklahoma, the net profits interest should be treated as a debt instrument.

For North Dakota, Colorado, Mississippi, Arkansas, Montana and Michigan 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, Colorado, Mississippi, Arkansas, Montana and Oklahoma, 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.

97

For Michigan, as long as the trust is taxed as a grantor trust under the Code and employs a revenue-based apportionment method to calculate severance tax due to Michigan, neither the trust nor Whiting should be required to withhold the income tax due Michigan on distributions made to an individual resident or nonresident trust unitholder.

For New Mexico, as long as the trust is taxed as a grantor trust under the Code, withholding applies unless (i) the unitholder agrees with the broker holding such units that the unitholder will pay the amount that the broker would be required to withhold, (ii) the total New Mexico withholding in any calendar quarter is less than $30, or (iii) the unitholder is a resident of New Mexico and submits appropriate proof of residence.

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 subsidiary, Whiting Oil and Gas Corporation, will convey the net profits interest to the trust in consideration for the issuance by the trust of 18,400,000 units, which will be distributed as a dividend to Whiting Petroleum Corporation. Of those trust units, 16,000,000 are being offered hereby and 2,400,000 will be subject to purchase by the underwriters pursuant to its over-allotment option. 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 Morgan Stanley & Co. 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’ over-allotment option is not exercised.

	Ownership of Trust Units Before Offering					Number of  Trust Units Being Offered		Ownership of Trust Units After Offering
Selling Trust Unitholder	Number		Percentage					Number		Percentage
Whiting Petroleum Corporation(1)		18,400,000		100.0	%		16,000,000		2,400,000		13.0	%(2)

(1) The address of this entity is 1700 Broadway, Suite 2300 Denver, Colorado 80290-2300.

(2) In the event that the underwriters’ over-allotment option is exercised in full, Whiting Petroleum Corporation will not own any trust units.

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

100

UNDERWRITING

Subject to the terms and conditions in an underwriting agreement dated                     , 2012, the underwriters named below, for whom Raymond James & Associates, Inc. and Morgan Stanley & Co. LLC are acting as representatives, have severally agreed to purchase from Whiting the number of trust units set forth opposite their names:

Underwriter	Number of Trust  Units
Raymond James & Associates, Inc.
Morgan Stanley & Co. LLC
J.P. Morgan Securities LLC.
Robert W. Baird & Co. Incorporated
Oppenheimer & Co. Inc.
RBC Capital Markets, LLC
Stifel, Nicolaus & Company, Incorporated
Morgan Keegan & Company, Inc.
Wunderlich Securities, Inc.
Total		16,000,000

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 certain other customary 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 over-allotment option 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. 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 2,400,000 additional trust units to cover over-allotments, if any, at the public offering price less the underwriting discounts 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 over-allotment option 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. The amounts are shown assuming both no exercise and full exercise of the underwriters’ over-allotment option.

	Per Unit	No Exercise	Full Exercise
Initial public offering price	$	$	$
Underwriting discounts	$	$	$
Proceeds, before expenses, to Whiting	$	$	$

101

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

The other expenses of this offering that are payable by Whiting are estimated to be $1.6 million (exclusive of underwriting discounts and structuring fee).

INDEMNIFICATION

Each of Whiting and the trust 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, neither Whiting nor the trust will 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 or the trust, as applicable, 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 or the trust’s contributions, as applicable, would be in the proportion that the proceeds (after underwriting discounts) that the applicable party receives from this offering bear to the proceeds (from underwriting discounts) that the underwriters receive. If Whiting or the trust, as applicable, cannot contribute in this proportion, the applicable party will contribute based on its respective faults and benefits, as set forth in the underwriting agreement.

LOCK-UP AGREEMENTS

Subject to specified exceptions, Whiting and the trust have 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 the representatives. 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. The representatives may, in their discretion and at any time without notice, release all or any portion of the securities subject to these agreements. The representatives 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 and in accordance with Regulation M under the Exchange Act, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of the trust units in order to facilitate the offering of trust units, including:

• short sales;

• syndicate covering transactions;

102

• imposition of penalty bids; and

• purchases to cover positions created by short sales.

Stabilizing transactions may include making short sales of trust units, which involve the sale by the underwriter of a greater number of trust units than it is required to purchase in this offering and purchasing trust units from Whiting by exercising the over-allotment option 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’ over-allotment option 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 over-allotment option, in whole or in part, or by purchasing trust units in the open market after the distribution has been completed. 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 over-allotment option.

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 after pricing 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 after the pricing of this offering.

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. In addition, affiliates of Raymond James & Associates, Inc., Morgan Stanley & Co. LLC, J.P. Morgan Securities LLC and RBC Capital Markets, LLC are lenders under Whiting Oil and Gas Corporation’s bank credit facility and each will receive its proportionate share of the net proceeds of the offering used to repay a portion of the outstanding balance under the credit facility. None of the underwriter or their affiliates have received any item of value other than cash compensation in connection with 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 intends to apply to list the trust units on the New York Stock Exchange under the symbol “WHZ.” 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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INDEX TO FINANCIAL STATEMENTS

Underlying Properties:
Report of Independent Registered Public Accounting Firm	F-2
Statements of Historical Revenues and Direct Operating Expenses for Each of the Three Years in the Period Ended December 31, 2011 (As Restated)	F-3
Notes to Statements of Historical Revenues and Direct Operating Expenses	F-4
Whiting USA Trust II:
Report of Independent Registered Public Accounting Firm	F-9
Statement of Assets and Trust Corpus as of December 8, 2011	F-10
Notes to Statement of Assets and Trust Corpus	F-11
Unaudited Pro Forma Financial Information	F-14
Unaudited Pro Forma Statement of Assets and Trust Corpus at December 31, 2011	F-15
Unaudited Pro Forma Statement of Distributable Income for the Year Ended December 31, 2011	F-16
Notes to Unaudited Pro Forma Financial Information	F-17

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Whiting Petroleum Corporation

Denver, Colorado

We have audited the accompanying statements of historical revenues and direct operating expenses of the Underlying Properties (the “Underlying Properties”) of Whiting Petroleum Corporation (“Whiting”) for each of the three years in the period ended December 31, 2011. These statements are the responsibility of the Whiting’s management. Our responsibility is to express an opinion on these statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Properties are not required to have, nor were we engaged to perform, an audit of the Underlying Properties’ internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Underlying Properties’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying statements were prepared to present the historical revenues and direct operating expenses as defined in Financial Accounting Standards Board Accounting Standards Codification Topic 932-10-S99-2, Extractive Activities — Oil and Gas, “Financial Statements of Oil and Gas Exchange Offers,” which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America, as discussed in Note 2 to the statements, and are not intended to be a complete presentation of Whiting’s interests in the Underlying Properties.

As discussed in Note 2 to the financial statements, the accompanying 2009 and 2010 statements of historical revenues and direct operating expenses have been restated to correct a misstatement.

In our opinion, the statements referred to above present fairly, in all material respects, the historical revenues and direct operating expenses of the Underlying Properties for each of the three years in the period ended December 31, 2011, on the basis of accounting discussed in Note 2 to the financial statements.

/s/ Deloitte & Touche LLP

Denver, Colorado

March 2, 2012

F-2

UNDERLYING PROPERTIES

STATEMENTS OF HISTORICAL REVENUES

AND DIRECT OPERATING EXPENSES

(In thousands)

	Year Ended December 31,
	2009		2010		2011
	as restated – see Note 2		as restated – see Note 2
Net revenues:
Oil sales	$	85,826	$	104,667	$	120,879
Natural gas sales		19,791		19,041		16,893
Total revenues		105,617		123,708		137,772
Direct operating expenses:
Lease operating		35,076		37,391		39,377
Production tax		5,718		6,571		7,536
Total direct operating expenses		40,794		43,962		46,913
Excess of revenues over direct operating expenses	$	64,823	$	79,746	$	90,859

The accompanying notes are an integral part of this statement.

F-3

UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF HISTORICAL REVENUES

AND DIRECT OPERATING EXPENSES

For the years ended December 31, 2009, 2010 and 2011

1. UNDERLYING PROPERTIES

The accompanying statements present the revenues and direct operating expenses for the years ended December 31, 2009, 2010 and 2011 of net ownership interests in certain oil and natural gas properties located in the Rocky Mountains, Permian Basin, Gulf Coast and Mid-Continent regions of the United States (the “Underlying Properties”) owned by Whiting Petroleum Corporation’s wholly-owned subsidiary Whiting Oil and Gas Corporation (“Whiting”). Immediately prior to the closing of the initial public offering of units of beneficial interest in Whiting USA Trust II (the “Trust”), Whiting will convey to the Trust the right to receive 90% of the term net proceeds from these Underlying Properties (“Net Profits Interest”), with Whiting retaining title to the Underlying Properties.

2. BASIS OF PRESENTATION

The accompanying statements of historical revenues and direct operating expenses were derived from the historical accounting records of Whiting and are presented on the accrual basis of accounting before the effects of conveyance of the Net Profits Interest. Revenues and direct operating expenses relate to the historical net revenue interest and net working interest, respectively, in the Underlying Properties. Revenue from oil, natural gas and natural gas liquid sales is recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues are reported net of existing overriding and other royalties due to third parties. Direct operating expenses include lease operating expenses and production and ad valorem taxes. The amounts presented represent 100% of Whiting’s interests in the historical revenues and direct operating expenses of the Underlying Properties.

During the periods presented, the Underlying Properties were not accounted for as a separate division by Whiting and therefore certain costs such as depreciation, depletion and amortization, accretion of asset retirement obligation, general and administrative expenses, interest, corporate income taxes or other expenses of an indirect nature were not allocated to the individual properties. Due to the omission of these operating expenses of an indirect nature, the statements of historical revenues and operating expenses presented are not therefore indicative of the results of operations of the Underlying Properties or the Net Profits Interest prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). Historical statements reflecting financial position, results of operations and cash flows from operating, investing and financing activities prepared in accordance with GAAP are not presented because the information necessary to prepare such statements is neither reasonably available on an individual property basis nor practicable to obtain in these circumstances. Accordingly, the statements of historical revenues and direct operating expenses of the Underlying Properties are presented in lieu of the financial statements required under Rule 3-01 and 3-02 of the SEC Regulation S-X and in accordance with FASB ASC Topic 932-10-S99-2, Extractive Activities — Oil and Gas, “Financial Statements of Oil and Gas Exchange Offers”.

Use of Estimates.    The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include accrued revenue, accrued expenses, and proved oil and gas reserves, which are used to derive the standardized measure of discounted future net cash flows. Although management believes these estimates are reasonable, actual results could differ from these estimates.

F-4

Concentration of Credit Risk.    The underlying properties principally sell their oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. The following table presents the percentages of oil and natural gas sales from the underlying properties sold to each significant purchaser for the years ended December 31, 2009, 2010 and 2011:

	2009			2010			2011
Plains Marketing, LP		11	%		14	%		16	%
Chevron USA		13	%		13	%		14	%
ConocoPhillips		13	%		13	%		13	%
Marathon Oil Corporation		11	%		11	%		11	%

The loss of one or all of these purchasers 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 they 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 their business.

Correction of Prior Year Balances.    In the accompanying statements of historical revenues and direct operating expenses, errors pertaining to the recognition of ad valorem taxes within lease operating expenses have been corrected. These corrections increased lease operating expenses and total direct operating expenses from amounts previously reported by $3.1 million and $3.5 million for the years ended December 31, 2009 and 2010, respectively, and decreased excess revenues over direct operating expenses by $3.1 million and $3.5 million, respectively, for those same periods.

3. SUBSEQUENT EVENTS

Events occurring after December 31, 2011 were evaluated through March 2, 2012, the date that these financial statements were issued, to ensure that any subsequent events that met the criteria for recognition and/or disclosure in this report have been included.

4. DISCLOSURES ABOUT OIL AND GAS ACTIVITIES (UNAUDITED)

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

F-5

As of December 31, 2011, all of the Trust’s oil and gas reserves are attributable to properties within the United States. A summary of the changes in quantities of proved oil and gas reserves for the years ended December 31, 2009, 2010 and 2011, are as follows:

	Oil (MBbl)			Natural Gas (MMcf)			Total (MBOE)
Balance — January 1, 2009		12,767			25,357			16,994
Revisions to previous estimates		6,595			13,983			8,925
Extensions and discoveries		—			4			1
Production		(1,572	)		(4,318	)		(2,292	)
Balance — December 31, 2009		17,790			35,026			23,628
Revisions to previous estimates		(572	)		(4,275	)		(1,285	)
Extensions and discoveries		10			15			13
Production		(1,459	)		(3,335	)		(2,015	)
Balance — December 31, 2010		15,769			27,431			20,341
Revisions to previous estimates		38			(3,768	)		(590	)
Extensions and discoveries		262			608			363
Production		(1,382	)		(2,717	)		(1,834	)
Balance — December 31, 2011		14,687			21,554			18,280
Proved developed reserves:
December 31, 2008		11,809			21,972			15,471
December 31, 2009		16,031			26,779			20,494
December 31, 2010		14,881			23,824			18,852
December 31, 2011		14,528			21,284			18,076
Proved undeveloped reserves:
December 31, 2008		959			3,386			1,523
December 31, 2009		1,759			8,247			3,133
December 31, 2010		888			3,607			1,489
December 31, 2011		159			270			204

Notable changes to proved reserves for the year ended December 31, 2011 included:

• Revisions to previous estimates.    In 2011, revisions to previous estimates decreased proved reserves by a net amount of 590 MBOE. Included in these revisions were 38 MBbl of upward adjustments to crude oil reserves and 3.8 Bcf of downward adjustments to natural gas reserves. The reduction in natural gas reserves was primarily attributable to the removal of five Permian Basin oil and gas wells from the proved undeveloped reserve category. The continued environment of low natural gas prices affected the economic viability of these proved undeveloped locations. Whiting therefore no longer planned to drill these wells within five years of their initial inclusion as proved undeveloped reserves, and they were removed from the proved undeveloped reserve category accordingly, as required by SEC oil and gas reserve rules. The resulting negative oil revision associated with the removal of these five wells was more than offset by the upward adjustment in oil reserves that was attributable to higher crude oil prices incorporated into reserves estimates at December 31, 2011 as compared to December 31, 2010. This increase in oil price used in year-end reserve estimates from $79.43 per Bbl at December 31, 2010 to $96.19 per Bbl at December 31, 2011 extended the economic lives of many oil wells.

F-6

Notable changes in proved reserves for the year ended December 31, 2010 included:

• Revisions to previous estimates. In 2010, revisions to previous estimates decreased proved reserves by a net amount of 1,285 MBOE. Included in these revisions were 572 MBbl of downward adjustments to crude oil reserves and 4.3 Bcf of downward adjustments to natural gas reserves. Both of these reserve reductions were primarily attributable to a negative revision of the proved reserves associated with a Clearfork waterflood project in the Keystone, South field. Oil response to water injection was less than expected due to reservoir continuity and conformance issues.

Notable changes in proved reserves for the year ended December 31, 2009 included:

• Revisions to previous estimates. In 2009, revisions to previous estimates increased proved reserves by a net amount of 8,925 MBOE. Included in these revisions were 14.0 Bcf of upward adjustments to natural gas reserves and 6,594 MBbl of upward adjustments to crude oil reserves. These increases were mainly due to higher oil prices of $61.18 per Bbl of oil in reserve estimates at December 31, 2009, as compared to $44.60 per Bbl of oil at December 31, 2008. This increase in oil price extended the economic lives of many oil wells, which increased the estimate of proved oil and the associated gas reserves.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with the provisions of FASB ASC Topic 932, Extractive Activities — Oil and Gas. Future cash inflows were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month periods ended December 31, 2009, 2010 and 2011, respectively) to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming the continuation of existing economic conditions. The standardized measure of discounted future net cash flows has not been reduced by federal or state income taxes due to taxable income being passed through to the unitholders of the Trust.

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

	December 31,
	2009			2010			2011
Future cash inflows	$	1,080,650		$	1,243,215		$	1,410,213
Future production costs		(462,024	)		(538,019	)		(673,031	)
Future development costs		(39,146	)		(17,956	)		(26,619	)
Future net cash flows	$	579,480		$	687,240		$	710,563
10% annual discount for estimated timing of cash flows		(247,472	)		(296,299	)		(302,060	)
Standardized measure of discounted future net cash flows (1)	$	332,008		$	390,941		$	408,503

(1) No provision for federal or state income taxes has been provided because taxable income is passed through to unitholders of the Trust.

F-7

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

	December 31,
	2009			2010			2011
Beginning of year	$	168,250		$	332,008		$	390,941
Sale of oil and gas produced, net of production costs (1)		(64,823	)		(79,746	)		(90,859	)
Net changes in prices and production costs (1)		92,206			123,652			76,353
Extensions and discoveries less related costs		11			231			6,870
Previously estimated development costs incurred during the period		20,229			39,146			17,956
Changes in estimated future development costs		(29,262	)		(34,086	)		(20,693	)
Revisions of previous quantity estimates		128,572			(23,465	)		(11,159	)
Accretion of discount		16,825			33,201			39,094
End of year	$	332,008		$	390,941		$	408,503

(1) The 2009 and 2010 amounts have been revised for the effects of the prior year corrections discussed in Note 2 to these financial statements.

Future net revenues included in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves incorporate weighted average sales prices (inclusive of adjustments for quality and location) in effect at December 31, 2009, 2010 and 2011 as follows:

	2009		2010		2011
Oil (per Bbl)	$	54.92	$	72.84	$	87.15
Gas (per Mcf)	$	4.40	$	5.96	$	6.04

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Unitholders of

Whiting USA Trust II

Denver, Colorado

We have audited the accompanying statement of assets and trust corpus of Whiting USA Trust II (the “Trust”) as of December 8, 2011. This financial statement is the responsibility of the Trust’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

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

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

In our opinion, the statement of assets and trust corpus presents fairly, in all material respects, the assets, liabilities, and trust corpus of Whiting USA Trust II as of December 8, 2011, on the basis of accounting discussed in Note 2 to the financial statement.

/s/ Deloitte & Touche LLP

Denver, Colorado

December 16, 2011

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WHITING USA TRUST II

STATEMENT OF ASSETS AND TRUST CORPUS

	December 8, 2011
ASSETS
Cash and short-term investments	$	10
TRUST CORPUS
Trust Corpus	$	10

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

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WHITING USA TRUST II

NOTES TO STATEMENT OF ASSETS AND TRUST CORPUS

1. ORGANIZATION OF THE TRUST

Whiting USA Trust II (the “Trust”) is a statutory trust formed on December 5, 2011 under the Delaware Statutory Trust Act, pursuant to a trust agreement (the “Trust Agreement”) among Whiting Oil and Gas Corporation (“Whiting Oil and Gas”) as trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and Wilmington Trust, National Association (the “Delaware Trustee”). The initial capitalization of the Trust estate was funded by Whiting Petroleum Corporation (“Whiting”) on December 8, 2011.

The Trust was created to acquire and hold a term net profits interest (“NPI”) for the benefit of the Trust unitholders pursuant to a conveyance from Whiting Oil and Gas, which is a subsidiary of Whiting, to the Trust. The term NPI is an interest in underlying properties located in the Rocky Mountains, Permian Basin, Gulf Coast and Mid-Continent regions (the “underlying properties”). These oil and gas properties include interests in approximately 1,300 producing oil and gas wells. The NPI will be the only asset of the Trust, other than cash held for future Trust expenses.

The NPI is passive in nature, and the Trustee will have no management control over and no responsibility relating to the operation of the underlying properties. After the conveyance of term NPI to the Trust, Whiting Oil and Gas will retain interests in each of the underlying properties. The NPI entitles the Trust to receive 90% of the net proceeds from the sale of production from the underlying properties. The NPI will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), and the Trust will soon thereafter wind up its affairs and terminate.

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Term Net Profits Interest.    The Trust uses the modified cash basis of accounting to report Trust receipts from the term NPI and payments of expenses incurred. The actual cash distributions from Whiting to the Trust will be made based on the terms of the conveyance that created the Trust’s NPI. The term NPI entitles the Trust to receive revenues (oil, gas and natural gas liquid sales) less expenses (the amount by which all royalties; lease operating expenses including well workover costs; development costs; production and property taxes; payments made by Whiting to the hedge counterparty upon settlements of hedge contracts; maintenance expenses; producing overhead; and amounts that may be reserved for future development, maintenance or operating expenses, which reserve amounts may not exceed $2.0 million; exceed hedge payments received by Whiting under hedge contracts and other non-production revenue) of the underlying properties multiplied by 90% (term NPI percentage). Actual cash receipts may vary due to timing delays of cash receipts from the property operators or purchasers and due to wellhead and pipeline volume balancing agreements or practices.

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

a. Income from net profits interest is recorded when NPI distributions are received by the Trust;

b. Distributions to Trust unitholders are recorded when declared and paid by the Trust;

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b. Trust general and administrative expenses (which include the Trustee’s fees as well as accounting, engineering, legal and other professional fees) are recorded when paid;

c. Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under generally accepted accounting principles in the United States of America (“GAAP”);

d. Amortization of the investment in net profits interest is calculated based on the units-of-production method. Such amortization will be charged directly to the Trust corpus and will not affect cash earnings; and

e. Any impairments of the investment in net profits interest will likewise be charged directly to Trust corpus.

While these statements differ from financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues and distributions is considered to be the most meaningful because quarterly distributions to the Trust unitholders are based on net cash receipts. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by FASB ASC Topic 932-10-S99-4, Extractive Activities — Oil and Gas, “Financial Statements of Royalty Trusts”.

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

Use of Estimates.    The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Significant estimates that will impact the Trust’s financial statements include estimates of proved oil and natural gas reserves which are used to compute the Trust’s amortization of its investment in net profits interest. Actual results could differ from those estimates.

Cash and Short-Term Investments.    Cash and short-term investments include all highly liquid short-term investments with original maturities of three months or less.

Investment in Net Profits Interest.    The conveyance of the NPI to the Trust will be accounted for as a transfer of properties between entities under common control. Accordingly, the Trust’s investment in net profits interest will be recorded at the historical cost to Whiting Oil and Gas, which is determined by allocating the historical net book value of Whiting Oil and Gas’ proved oil and gas properties based on the fair value of the conveyed net profits interest in the Underlying Properties relative to the fair value of Whiting Oil and Gas’ proved properties. The carrying value of the Trust’s investment in net profits interest will not necessarily be indicative of the fair value of such net profits interest.

Amortization of the investment in net profits interest will be calculated on a units-of-production basis, whereby the Trust’s cost basis is divided by the proved reserves attributable to the net profits interest. Such amortization will not reduce distributable income but rather will be charged directly to trust corpus. Revisions to estimated future units-of-production will be treated on a prospective basis beginning on the date significant revisions are known.

The Trust will evaluate impairment of its investment in net profits interest by comparing the undiscounted cash flows expected to be realized from the investment in net profits interest to the NPI carrying value. If the expected future undiscounted cash flows are less than the carrying value, the Trust will recognize an impairment loss for the difference between the carrying value and the estimated fair value of the investment in net profits interest. The determination of whether the NPI is impaired requires a significant amount of judgment by the Trustee and is based on the best information available to the Trustee at the time of the evaluation. If market conditions or oil and gas production deteriorate, write-downs could be required.

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3. SUBSEQUENT EVENTS

Events occurring after December 8, 2011 were evaluated through December 16, 2011, the date that these financial statements were issued, to ensure that any subsequent events that met the criteria for recognition and/or disclosure in this report have been included.

4. INCOME TAXES

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

For Montana state income tax purposes, Whiting must withhold from its NPI payments to the Trust, an amount equal to 6% of the net amount payable to the Trust from the sale of oil and gas in Montana. For Arkansas, Colorado, Michigan, Mississippi, New Mexico, North Dakota and Oklahoma, neither the Trust nor Whiting will be withholding 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 Internal Revenue Code.

5. DISTRIBUTIONS TO UNITHOLDERS

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

6. RELATED PARTY TRANSACTIONS

Operating Overhead — Pursuant to the terms of its applicable joint operating agreements, Whiting deducts from the gross oil and gas sales proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally, with respect to those underlying properties for which Whiting is the operator but where there is no operating agreement in place, Whiting deducts from the gross proceeds an overhead fee calculated in the same manner that Whiting allocates overhead to other similarly owned properties, which is customary practice in the oil and gas industry. Operating overhead activities include various engineering, legal, and administrative functions. The fee is adjusted annually pursuant to the Council of Petroleum Accountants Societies, Inc. (“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.

Administrative Services Fee — Under the terms of the administrative services agreement, the Trust will pay a quarterly administration fee of $50,000 to Whiting 60 days following the end of each calendar quarter.

Trustee Administrative Fee — Under the terms of the Trust agreement, the Trust will pay an annual administrative fee to the Trustee of $175,000, which will be paid in four quarterly installments of $43,750 each and will be billed in arrears. Starting in 2017, such fee escalates by 2.5% each year.

F-13

WHITING USA TRUST II

UNAUDITED PRO FORMA FINANCIAL INFORMATION

The following unaudited pro forma statement of assets and trust corpus and unaudited pro forma statement of distributable income for the Trust have been prepared to illustrate the conveyance of the term net profits interest in the underlying properties to the Trust by Whiting Oil and Gas Corporation. The unaudited pro forma statement of assets and trust corpus presents the formation of the Trust as if it had occurred on December 31, 2011, and giving effect to the net profits interest conveyance as if it occurred on that date. The unaudited pro forma statement of distributable income for the year ended December 31, 2011, gives effect to the Trust formation and net profits interest conveyance as if they occurred as of January 1, 2011, reflecting only pro forma adjustments that are (i) directly attributable to the transaction, (ii) expected to have a continuing impact on the combined results, and (iii) factually supportable.

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

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

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WHITING USA TRUST II

UNAUDITED PRO FORMA STATEMENT OF ASSETS AND TRUST CORPUS

December 31, 2011

	Historical		Adjustments			Pro Forma
ASSETS
Cash and short-term investments	$	10	$	—		$	10
Investment in Net Profits Interest (Note 5)		—		174,699,510	(a)		174,699,510
	$	10	$	174,699,510		$	174,699,520
TRUST CORPUS
18,400,000 Trust units issued and outstanding (Note 5)	$	10	$	174,699,510	(a)	$	174,699,520

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

F-15

WHITING USA TRUST II

UNAUDITED PRO FORMA STATEMENT OF DISTRIBUTABLE INCOME

	Year Ended December  31, 2011
Historical results
Income from Net Profits Interest	$	65,335,668
Pro Forma Adjustments
Less:
Trust general and administrative expenses (Note 5)		(375,000	)(b)
State income tax withholdings (Note 5)		(94,454	)(c)
Distributable income	$	64,866,214
Distributable income per unit (Note 5)	$	3.53	(d)

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

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WHITING USA TRUST II

NOTES TO UNAUDITED PRO FORMA FINANCIAL INFORMATION

1. BASIS OF PRESENTATION

Whiting USA Trust II (the “Trust”) will own a term net profits interest in oil and gas producing properties located in the Rocky Mountains, Permian Basin, Gulf Coast and Mid-Continent regions of the United States. These producing properties are owned by Whiting Oil and Gas Corporation, which is a subsidiary of Whiting Petroleum Corporation (referred to hereafter as “Whiting”). The term net profits interest (“NPI”) entitles the Trust to receive 90% of the net proceeds attributable to Whiting’s interest in the sale of oil and gas production from these properties. The NPI will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), and the Trust will soon thereafter wind up its affairs and terminate.

The Trust was formed on December 5, 2011 under Delaware law to acquire and hold the net profits interest for the benefit of the holders of the Trust units. The net profits interest is passive in nature, and the Trustee will have no management control over and no responsibility relating to the operation of the underlying properties.

The unaudited pro forma statement of assets and trust corpus assumes formation and funding of the Trust and conveyance of the net profits interest at December 31, 2011. The unaudited pro forma statement of distributable income assumes the conveyance of the net profits interest and Trust formation as of January 1, 2011.

Whiting believes that the assumptions used provide a reasonable basis for presenting the effects directly attributable to this transaction. However, due to the omission of certain general and administrative expenses that are not factually supportable and not therefore reliably determinable, these unaudited pro forma financial statements may not be indicative of the results to be realized in the future.

This unaudited pro forma financial information should be read in conjunction with the Statement of Assets and Trust Corpus for the Trust and the Statements of Historical Revenues and Direct Operating Expenses for the underlying properties and related notes, respectively, for the periods presented.

2. TRUST ACCOUNTING POLICIES

The unaudited pro forma statement of distributable income was derived from the historical accounting records of the underlying properties.

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

Income determined in accordance with generally accepted accounting principles in the United States (“GAAP”) would include all expenses incurred for the period presented. However, the Trust serves as a pass-through entity, with expenses for depletion, interest and income taxes, other than Montana state income tax to which the Trust is subject, being based upon the status and elections of the Trust unitholders. Thus, the unaudited pro forma statement of distributable income purports to show distributable income, defined as income of the Trust available for distribution to the Trust unitholders before application of those unitholders’ additional

F-17

expenses, if any, for depreciation, depletion and amortization, interest and income taxes. Revenues are reflected net of existing royalties and overriding royalties associated with Whiting’s interests. While this financial statement differs from financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues, expenses, and distributions is considered to be the most meaningful because quarterly distributions to the Trust unitholders are based on the net cash receipts generated from the production and sale of the reserves of the underlying properties.

Investment in the net profits interest is recorded initially at Whiting’s historic cost in accordance with FASB ASC Topic 845-10-S99-1, Nonmonetary Transactions, “Transfers of Nonmonetary Assets By Promoters or Shareholders”, and is periodically assessed to determine whether its aggregate value has been impaired below its total capitalized cost based on the underlying properties. The Trust will provide a write-down to its investment in the net profits interest to the extent that total capitalized costs, less accumulated depreciation, depletion and amortization, exceed undiscounted future net revenues attributable to the proved oil and gas reserves of the underlying properties. Any such write-down would be charged directly to trust corpus and would not reduce distributable income.

3. INCOME TAXES

The Trust is a Delaware statutory trust and therefore is not subject to federal income taxes. Accordingly no recognition is given to federal income taxes in these financial statements. The Trust unitholders will be treated as the owners of Trust income and corpus, and the entire taxable income of the Trust will be reported by the Trust unitholders on their respective tax returns.

For Montana state income tax purposes, Whiting must withhold from its NPI payments to the Trust, an amount equal to 6% of the net amount payable to the Trust from the sale of oil and gas in Montana. For Arkansas, Colorado, Michigan, Mississippi, New Mexico, North Dakota and Oklahoma, neither the Trust nor Whiting will be withholding 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 Internal Revenue Code.

4. INCOME FROM NET PROFITS INTEREST

As Trust receipts from the net profits interest will be based on 90% of the net proceeds (which are attributable to Whiting’s interest in the sale of oil and gas production from the underlying properties less applicable costs and expenses) that have been received by Whiting in cash, the adjustment amounts in the table below (“Adjust from accrual basis of accounting to modified cash basis”) convert the excess revenues over direct operating expenses of the underlying properties from the accrual basis of accounting to the modified cash basis of accounting.

	Year Ended December 31,
	2011
Excess of revenues over direct operating expenses of underlying properties	$	90,859,246
Adjust from accrual basis of accounting to modified cash basis		(971,149	)(1)
Modified cash basis excess revenues over direct operating expenses		89,888,097
Development costs on a modified cash basis		(17,292,910	)
Total net proceeds		72,595,187
Times the term NPI percentage		90	%
Income from net profits interest	$	65,335,668

(1) Because quarterly cash distributions to the Trust will be made by the Trustee no later than 60 days following the end of each quarter, this adjustment assumes that the last quarterly distribution to the Trust for 2011

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would have been made by November 29, 2011 (covering net cash proceeds received by Whiting for oil sales through September 30, 2011 and gas sales through August 31, 2011) and the last quarterly distribution for 2010 would have been made by November 29, 2010 (covering net cash proceeds received by Whiting for oil sales through September 30, 2010 and gas sales through August 31, 2010). As such, this amount adjusts excess of revenues over direct operating expense in order to (i) exclude net cash proceeds attributable to oil sales for October, November and December of 2011, (ii) exclude net cash proceeds attributable to natural gas sales for September, October, November and December of 2011, (iii) include net proceeds attributable to oil sales for October, November and December of 2010, and (iv) include net proceeds attributable to natural gas sales for September, October, November and December of 2010.

5. PRO FORMA ADJUSTMENTS

(a) Whiting will convey the net profits interest to the Trust in exchange for 18,400,000 trust units.

The net profits interest is recorded at the historical cost of Whiting as follows:

Oil and gas properties	$	381,852,133
Accumulated depreciation and depletion		(187,741,566	)
Net predecessor cost of net profits interest conveyed to the Trust	$	194,110,567
Times 90% net profits interest to Trust	$	174,699,510

(b) The Trust will pay an annual administrative fee to Whiting of $200,000 and an annual administrative fee to the trustee of $175,000.

Including the above administrative fees of $375,000 to Whiting and the trustee, the Trust estimates incurring aggregate general and administrative expenses of $1,000,000 in 2012 and annually thereafter. The Trust’s aggregate general and administrative costs will encompass legal fees, accounting fees, engineering fees, printing costs, the annual administrative fee paid to Whiting and the trustee, and other expenses properly chargeable to the Trust. If the estimated general and administrative expenses were included in the unaudited pro forma statement of distributable income, the distributable income would be $64,241,214 or $3.49 per unit for the year ended December 31, 2011. Due to the omission of general and administrative expenses other than the $375,000 administrative fee from the unaudited pro forma statement of distributable income, this pro forma financial statement may not be indicative of the results to be realized going forward.

(c) For Montana state income tax purposes, Whiting must withhold from its NPI payments to the Trust, an amount equal to 6% of the net amount payable to the Trust from the sale of oil and gas in Montana.

For Arkansas, Colorado, Michigan, Mississippi, New Mexico, North Dakota and Oklahoma, neither the Trust nor Whiting will be withholding 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 Internal Revenue Code.

(d) Assumes the issuance of 18,400,000 trust units.

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Appendix A

CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS

9601 AMBERGLEN BLVD., SUITE 117 AUSTIN, TEXAS 78729-1106 512-249-7000 306 WEST SEVENTH STREET, SUITE 302 FORT WORTH, TEXAS 76102-4987 817-336-2461 www.cgaus.com 1000 LOUISIANA STREET, SUITE 625 HOUSTON, TEXAS 77002-5008 713-651-9944

December 9, 2011

Whiting USA Trust II

1700 Broadway, Suite 2300

Denver, Colorado 80290-2300

Re:	Evaluation Summary — SEC Price
	Whiting USA Trust II Underlying Properties
	Total Proved Reserves
	Certain Properties Located in Various States
	As of December 31, 2011
	Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue

Gentlemen:

As requested, we are submitting our estimates of total proved reserves and forecasts of economics attributable to the underlying properties, from which a net profits interest will be formed and then conveyed by Whiting Petroleum Corporation to the Whiting USA Trust II. These certain oil and gas properties are located in Texas, Wyoming, North Dakota, Colorado, New Mexico, Mississippi, Arkansas, Montana, Michigan and Oklahoma. Also included in the tables below are the total proved reserves attributable to the same underlying properties estimated to be produced by December 31, 2021, which is the estimated date of termination for Whiting USA Trust II. This report, completed December 9, 2011 covers 100% of the total proved reserves estimated for Whiting USA Trust II. This report includes results for an SEC pricing scenario. The results of this evaluation are presented in the accompanying tabulations, with a composite summary presented below:

Underlying Properties Full Economic Life
		Proved Developed Producing		Proved Developed Non-Producing		Proved Undeveloped		Total Proved
Net Reserves
Oil	- Mbbl		13,609.4		396.8		159.2		14,165.4
Gas	- MMcf		19,608.1		1,675.8		270.3		21,554.2
NGL	- Mbbl		503.9		18.1		0.0		522.0
Equivalent*	- Mbbl		17,381.3		694.3		204.2		18,279.8
Revenue
Oil	- M$		1,194,081.4		36,701.4		14,736.7		1,245,519.6
Gas	- M$		117,403.6		10,812.3		2,059.7		130,275.6
NGL	- M$		33,430.1		988.2		0.0		34,418.2
Severance Taxes	- M$		69,796.4		2,585.0		1,101.1		73,482.5
Ad Valorem Taxes	- M$		41,803.7		1,262.7		168.7		43,235.1
Operating Expenses	- M$		543,120.9		10,115.1		3,077.2		556,313.2
Investments	- M$		19,487.3		2,872.9		4,259.4		26,619.6
Net Operating Income	- M$		670,707.0		31,666.1		8,189.9		710,563.1
Discounted @ 10%	- M$		391,804.4		12,706.6		3,991.8		408,502.8

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Whiting USA Trust II

December 9, 2011

Page 2

Underlying Properties Reserves Estimated to be Produced by December 31, 2021
		Proved Developed Producing		Proved Developed Non-Producing		Proved Undeveloped		Total Proved
Net Reserves
Oil	- Mbbl		8,591.7		137.8		114.9		8,844.4
Gas	- MMcf		14,605.3		741.4		189.3		15,536.1
NGL	- Mbbl		338.8		14.3		0.0		353.1
Equivalent*	- Mbbl		11,364.7		275.7		146.5		11,786.9
Revenue
Oil	- M$		755,810.6		12,753.4		10,632.2		779,196.2
Gas	- M$		87,119.7		4,588.2		1,442.2		93,150.0
NGL	- M$		22,464.1		781.8		0.0		23,245.9
Severance Taxes	- M$		45,912.3		995.4		783.5		47,691.3
Ad Valorem Taxes	- M$		25,883.7		483.5		127.5		26,494.7
Operating Expenses	- M$		282,201.6		2,507.3		1,220.6		285,929.5
Investments	- M$		19,487.3		2,080.0		4,259.4		25,826.7
Net Operating Income	- M$		491,909.5		12,057.1		5,683.3		509,649.9
Discounted @ 10%	- M$		348,277.8		7,893.7		3,380.9		359,552.5

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

The discounted cash flow value shown in the previous two tables should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc.

Hydrocarbon Pricing

As requested for the SEC scenario, initial WTI spot oil and Henry Hub Gas Daily prices of $96.19 per bbl and $4.12 per MMBtu, respectively, were adjusted individually to WTI posted pricing at $92.81 per bbl and Houston Ship Channel pricing at $4.06 per MMBtu, as of December 31, 2011. Further adjustments were applied on a lease level basis for oil price differentials, gas price differentials and heating values as furnished by your office. Prices were not escalated in the SEC scenario. The average adjusted prices used in the estimation of proved reserves for the underlying properties full economic life were $87.93 per bbl of oil, $65.93 per bbl of natural gas liquids and $6.04 per mcf of natural gas. For the proved reserves of the underlying properties estimated to be produced by December 31, 2021, the average adjusted prices were $88.01 per bbl of oil, $65.83 per bbl of natural gas liquids and $6.00 per mcf of natural gas.

Capital, Expenses and Taxes

Capital expenditures, lease operating expenses and Ad Valorem tax values were forecast as provided by your office. As you explained, the capital costs were based on the most current estimates, lease operating expenses were based on the analysis of historical actual expenses, operating overhead is included for operated properties and no credit or deduction was made for producing overhead paid to the company by other owners of the operated properties. Capital costs and lease operating expenses were held constant in accordance with SEC guidelines. Severance tax rates were applied at normal state percentages of oil and gas revenue.

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Whiting USA Trust II

December 9, 2011

Page 3

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

Reserve Estimation Methods

The methods employed in estimating reserves are described in page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

Miscellaneous

An on-site field inspection of the properties has not been performed. The mechanical operation or conditions of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included.

The reserve estimates were based on interpretations of factual data furnished by your office. We have used all methods and procedures as we considered necessary under the circumstances to prepare the report. We believe that the assumptions, data, methods and procedures were appropriate for the purpose served by this report. Production data, gas prices, gas price differentials, expense data, tax values and ownership interests were also supplied by you and were accepted as furnished. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data.

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The professional qualifications of the undersigned, the technical person primarily responsible for the preparation of this report, are included as an attachment to this letter.

Yours very truly,

Robert D. Ravnaas, P.E.

Executive Vice President

Cawley, Gillespie & Associates

Texas Registered Engineering Firm F-693

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APPENDIX

Explanatory Comments for Individual Tables

HEADINGS

Table Number

Effective Date of the Evaluation

Identity of Interest Evaluated

Reserve Classification and Development Status

Operator — Property Name

Field (Reservoir) Names — County, State

FORECAST

(Columns)
(1)(11)(21)	Calendar or Fiscal years/months commencing on effective date.
(2)(3)(4)	Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.
(5)(6)(7)	Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.
(8)	Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
(9)	Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
(10)	Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
(12)	Revenue derived from oil sales — column (5) times column (8).
(13)	Revenue derived from gas sales — column (6) times column (9).
(14)	Revenue derived from NGL sales — column (7) times column (10).
(15)	Revenue derived from other sources.
(16)	Revenue derived from hedge positions.
(17)	Total Revenue — sum of column (12) through column (16).
(18)	Production-Severance taxes deducted from gross oil and NGL revenue.
(19)	Production-Severance taxes deducted from gross gas revenue.
(20)	Revenue after taxes — column (17) less column (18) and column (19).
(22)	Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS.
(23)	Ad Valorem taxes.
(24)	Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
(25)	3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
(26)	Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.
(27)	Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
(28)(29)	Future Net Cash Flow is column (18) less the total of column (19), column (22), column (24), column (25), column (26) and column (27). The data in column (28) are accumulated in column (29). Federal income taxes have not been considered.
(30)	Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.
MISCELLANEOUS
Input Data	• Evaluation parameters such as rates, tax percentages, and expenses are shown below columns (21-26).
Interests	• Initial and final expense and revenue interests are shown below columns (27-28).
DCF Profile	• The cash flow discounted at six different rates are shown at the bottom of columns (29-30). Interest has been compounded monthly.
Life	• The economic life of the appraised property is noted in the lower right-hand corner of the table.
Footnotes	• Well ID information or other pertinent comments may be shown in the lower left-hand footnotes.

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APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as “decline curve” analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

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APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

“(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

“(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

“(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

“(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

“(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

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“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

“(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

“(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where

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geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S-K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

“(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”

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Professional Qualifications of Robert D. Ravnaas, P.E.

President of Cawley, Gillespie & Associates

Mr. Ravnaas has been a Petroleum Consultant for Cawley, Gillespie & Associates (CG&A) since 1983, and became Executive Vice President in 1999. He has completed numerous field studies, reserve evaluations and reservoir simulation, waterflood design and monitoring, unit equity determinations and producing rate studies. He has testified before the Texas Railroad Commission in unitization and field rules hearings. Prior to CG&A he worked as a Production Engineer for Amoco Production Company. Mr. Ravnaas received a B.S. with special honors in Chemical Engineering from the University of Colorado at Boulder, and a M.S. in Petroleum Engineering from the University of Texas at Austin. He is a registered professional engineer in Texas, No. 61304, and a member of the Society of Petroleum Engineers (SPE), the Society of Petroleum Evaluation Engineers, the American Association of Petroleum Geologists and the Society of Professional Well Log Analysts.

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16,000,000 Trust Units

WHITING USA TRUST II

PROSPECTUS

RAYMOND JAMES	MORGAN STANLEY
J.P. MORGAN BAIRD OPPENHEIMER & CO. RBC CAPITAL MARKETS STIFEL NICOLAUS WEISEL MORGAN KEEGAN WUNDERLICH SECURITIES

                    , 2012

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses Of Issuance And Distribution.

Set forth below are the expenses (other than underwriting discounts and structuring fees) expected to be incurred in connection with the issuance and distribution of the securities registered hereby all of which will be paid for by Whiting Petroleum Corporation. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing and the NYSE listing fee, the amounts set forth below are estimates.

Registration fee	$	44,282
FINRA filing fee		39,100
NYSE listing fee		125,000
Printing and engraving expenses		200,000
Fees and expenses of legal counsel		800,000
Accounting fees and expenses		350,000
Transfer agent and registrar fees		2,500
Trustee fees and expenses		3,500
Miscellaneous		35,618
Total	$	1,600,000

Item 14. Indemnification Of Directors And Officers.

The trust agreement provides that the trustee and its officers, agents and employees shall be indemnified from the assets of the trust against and from any and all liabilities, expenses, claims, damages or loss incurred by it individually or as trustee in the administration of the trust and the trust assets, including, without limitation, any liability, expenses, claims, damages or loss arising out of or in connection with any liability under environmental laws, or in the doing of any act done or performed or omission occurring on account of it being trustee or acting in such capacity, except such liability, expense, claims, damages or loss as to which it is liable under the trust agreement. In this regard, the trustee shall be liable only for fraud or gross negligence or for acts or omissions in bad faith and shall not be liable for any act or omission of any agent or employee unless the trustee has acted in bad faith or with gross negligence in the selection and retention of such agent or employee. The trustee is entitled to indemnification from the assets of the trust and shall have a lien on the assets of the trust to secure it for the foregoing indemnification.

Under the provisions of Section 145 of the Delaware General Corporation Law, Whiting Petroleum Corporation (“the Company”) is required to indemnify any present or former officer or director against expenses arising out of legal proceedings in which the director or officer becomes involved by reason of being a director or officer if the director or officer is successful in the defense of such proceedings. Section 145 also provides that the Company may indemnify a director or officer in connection with a proceeding in which he is not successful in defending if it is determined that he acted in good faith and in a manner reasonably believed to be in or not opposed to the best interests of the Company or, in the case of a criminal action, if it is determined that he had no reasonable cause to believe his conduct was unlawful. Liabilities for which a director or officer may be indemnified include amounts paid in satisfaction of settlements, judgments, fines and other expenses (including attorneys’ fees incurred in connection with such proceedings). In a stockholder derivative action, no indemnification may be paid in respect of any claim, issue or matter as to which the director or officer has been adjudged to be liable to the Company (except for expenses allowed by a court).

The Company’s Restated Certificate of Incorporation provides for indemnification of directors and officers of the Company to the full extent permitted by applicable law. Under the provisions of the Company’s Amended and Restated By-laws, the Company is required to indemnify officers or directors to a greater extent than under

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the current provisions of Section 145 of the Delaware General Corporation Law. Except with respect to stockholder derivative actions, the By-law provisions generally state that the director or officer will be indemnified against expenses, amounts paid in settlement and judgments, fines, penalties and/or other amounts incurred with respect to any threatened, pending or completed proceeding, provided that (i) such person acted in good faith and in a manner such person reasonably believed to be in or not opposed to the best interests of the Company, and (ii) with respect to any criminal action or proceeding, such person had no reasonable cause to believe his or her conduct was unlawful.

The foregoing standards also apply with respect to the indemnification of expenses incurred in a stockholder derivative suit. However, a director or officer may only be indemnified for settlement amounts or judgments incurred in a derivative suit to the extent that the Court of Chancery or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Court of Chancery or such other court shall deem proper.

In accordance with the Delaware General Corporation Law, the Company’s Restated Certificate of Incorporation contains a provision to limit the personal liability of the directors of the Company for violations of their fiduciary duty. This provision eliminates each director’s liability to the Company or its stockholders, for monetary damages except (i) for breach of the director’s duty of loyalty to the Company or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) under Section 174 of the Delaware General Corporation Law providing for liability of directors for unlawful payment of dividends or unlawful stock purchases or redemptions or (iv) for any transaction from which a director derived an improper personal benefit. The effect of this provision is to eliminate the personal liability of directors for monetary damages for actions involving a breach of their fiduciary duty of care, including any such actions involving gross negligence.

The Company has entered into indemnification agreements with its directors and executive officers. The indemnification agreements do not increase the extent or scope of indemnification provided to the Company’s directors and executive officers under the Company’s Restated Certificate of Incorporation and Amended and Restated By-laws, but set forth indemnification and expense advancement rights and establish processes and procedures determining entitlement to obtaining indemnification and advancement of expenses.

The Company maintains insurance policies that provide coverage to its directors and officers against certain liabilities.

Item 15. Recent Sales Of Unregistered Securities.

None.

Item 16. Exhibits and Financial Statement Schedules.

(a) Exhibits. The exhibits listed in the accompanying Exhibit Index are filed or incorporated by reference as part of this Registration Statement.

(b) Financial Statement Schedules. No financial statement schedules are required to be included herewith or they have been omitted because the information required to be set forth therein is not applicable.

Item 17. Undertakings.

The undersigned Registrants hereby undertake that, for purposes of determining any liability under the Securities Act of 1933, each filing of Registrant’s annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to Section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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The undersigned Registrants hereby undertake to provide to the underwriters at the closing specified in the underwriting agreement, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of each Registrant pursuant to the foregoing provisions, or otherwise, each Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by a Registrant of expenses incurred or paid by a director, officer or controlling person of a Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, that Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

For purpose of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in the form of prospectus filed by the Registrants pursuant to Rule 424(b) (1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.

For purposes of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of securities, of an offering of securities by the undersigned Registrants pursuant to this registration statement, each of the undersigned Registrants will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser: (i) any preliminary prospectus or prospectus of the undersigned Registrants relating to the offering required to be filed pursuant to Rule 424; (ii) any free writing prospectus relating to the offering prepared by or on behalf of the undersigned Registrants or used or referred to by the undersigned Registrants; (iii) the portion of any other free writing prospectus relating to the offering containing material information about the undersigned Registrants or their securities provided by or on behalf of the undersigned Registrants; and (iv) any other communication that is an offer in the offering made by the undersigned Registrants to the purchaser.

For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The undersigned Registrants hereby undertake to send to each trust unitholder at least on an annual basis a detailed statement of any transactions with the trustees, Whiting Petroleum Corporation or their respective affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to the trustees, Whiting Petroleum Corporation or their respective affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The undersigned Registrants hereby undertake to provide to the trust unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the trust.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-3 and has duly caused this amendment to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on March 2, 2012.

WHITING PETROLEUM CORPORATION
By:	/s/ James J. Volker
	James J. Volker
	Chairman and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, this amendment to the Registration Statement has been signed by the following persons in the capacities on March 2, 2012.

Signature	Title
/s/ James J. Volker James J. Volker	Chairman and Chief Executive Officer and Director (Principal Executive Officer)
/s/ Michael J. Stevens Michael J. Stevens	Vice President and Chief Financial Officer (Principal Financial Officer)
/s/ Brent P. Jensen Brent P. Jensen	Controller and Treasurer (Principal Accounting Officer)
* Thomas L. Aller	Director
* D. Sherwin Artus	Director
* Thomas P. Briggs	Director
* Philip E. Doty	Director
* William N. Hahne	Director
* Allan R. Larson	Director

*By /s/ James J. Volker James J. Volker Attorney-in-fact

S-1

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this amendment to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on March 2, 2012.

WHITING USA TRUST II

By:  WHITING PETROLEUM CORPORATION

By:	/s/ James J. Volker
	James J. Volker
	Chairman and Chief Executive Officer

S-2

EXHIBIT INDEX

Exhibit Number	Document Description
(1)	Form of Underwriting Agreement.
(3.1)	Restated Certificate of Incorporation of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 3.2 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 001-31899)].
(3.2)	Amended and Restated By-laws of Whiting Petroleum Corporation [Incorporated by reference to Exhibit 3.2 to Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 001-31899)].
(3.3)	Certificate of Trust of Whiting USA Trust II.†
(3.4)	Trust Agreement dated December 5, 2011 among Whiting Oil and Gas Corporation, The Bank of New York Mellon Trust Company, N.A. and Wilmington Trust, National Association.†
(3.5)	Form of Amended and Restated Trust Agreement among Whiting Oil and Gas Corporation, The Bank of New York Mellon Trust Company, N.A. and Wilmington Trust, National Association.†
(4.1)	Fifth Amended and Restated Credit Agreement, dated as of October 15, 2010, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the various other agents party thereto [Incorporated by reference to Exhibit 4 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated October 15, 2010 (File No. 001-31899)].
(4.2)	First Amendment to Fifth Amended and Restated Credit Agreement, dated as of April 15, 2011, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, the various other agents party thereto and the lenders party thereto. [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 001-31899)].
(4.3)	Second Amendment to Fifth Amended and Restated Credit Agreement, dated as of October 12, 2011, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto. [Incorporated by reference to Exhibit 4 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated October 12, 2011 (File No. 001-31899)].
(4.4)	Subordinated Indenture, dated as of April 19, 2005, by and among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, Whiting Programs, Inc., Equity Oil Company and The Bank of New York Trust Company, N.A., as successor trustee [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated September 21, 2010 (File No. 001-31899)].
(4.5)	Second Supplemental Indenture, dated September 24, 2010, among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating the 6.5% Senior Subordinated Notes due 2018 [Incorporated by reference to Exhibit 4.2 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated September 21, 2010 (File No. 001-31899)].
(4.6)	Indenture, dated October 4, 2005, by and among Whiting Petroleum Corporation, Whiting Oil and Gas Corporation, Whiting Programs, Inc. and The Bank of New York Trust Company, N.A., as successor trustee [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated October 4, 2005 (File No. 001-31899)].
(4.7)	Rights Agreement, dated as of February 23, 2006, between Whiting Petroleum Corporation and Computershare Trust Company, Inc. [Incorporated by reference to Exhibit 4.1 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated February 23, 2006 (File No. 001-31899)].

E-1

Exhibit Number	Document Description
(5.1)	Opinion of Richards, Layton & Finger, P.A. relating to the validity of the trust units.†
(8.1)	Opinion of Foley & Lardner LLP relating to tax matters.†
(10.1)	Form of Conveyance and Assignment from Whiting Oil and Gas Corporation to The Bank of New York Mellon Trust Company, N.A., as trustee of Whiting USA Trust II.†
(10.2)	Form of Administrative Services Agreement between Whiting Oil and Gas Corporation and Whiting USA Trust II.†
(10.3)	Form of Registration Rights Agreement between Whiting Petroleum Corporation and Whiting USA Trust II.†
(23.1)	Consent of Deloitte & Touche LLP with respect to the Underlying Properties and Whiting USA Trust II.
(23.2)	Consent of Deloitte & Touche LLP with respect to Whiting Petroleum Corporation.
(23.3)	Consent of Cawley, Gillespie & Associates, Inc.
(23.4)	Consent of Richards, Layton & Finger, P.A. (contained in Exhibit 5.1).†
(23.5)	Consent of Foley & Lardner LLP (contained in Exhibit 8.1).†
(24)	Powers of Attorney for Whiting Petroleum Corporation Directors.†
(99)	Summary Reserve Report of Cawley, Gillespie & Associates, Inc. (included as Appendix A to the prospectus).

† Previously filed.

E-2

EX-1

Exhibit 1

16,000,000 Trust Units

WHITING USA TRUST II

UNDERWRITING AGREEMENT

St. Petersburg, Florida

[l], 2012

Raymond James & Associates, Inc.

Morgan Stanley & Co. LLC

As Representatives of the Several Underwriters listed on Schedule I hereto

c/o Raymond James & Associates, Inc.

880 Carillon Parkway

St. Petersburg, Florida 33716

Ladies and Gentlemen:

Whiting Petroleum Corporation, a Delaware corporation (the “Company”), proposes, subject to the terms and conditions stated herein, to sell to the several Underwriters named in Schedule I hereto (the “Underwriters”) an aggregate of 16,000,000 units of beneficial interest (the “Trust Units”) in Whiting USA Trust II, a statutory trust formed under the laws of the State of Delaware (the “Trust”). The aggregate of 16,000,000 Trust Units to be purchased from the Company are called the “Firm Units.” In addition, the Company has agreed to sell to the Underwriters, upon the terms and conditions stated herein, up to an additional 2,400,000 Trust Units (the “Additional Units”) to cover over-allotments by the Underwriters, if any. The Firm Units and the Additional Units are collectively referred to in this Agreement as the “Units.” Raymond James & Associates, Inc. and Morgan Stanley & Co. LLC are acting as the representatives of the several Underwriters and in such capacity are referred to in this Agreement as the “Representatives.”

It is understood and agreed by all parties hereto that the Company and Whiting Oil and Gas Corporation, a wholly owned subsidiary of the Company (“WOGC,” and together with the Company, the “Company Parties”), have caused the formation of the Trust and will convey, or cause to be conveyed, to the Trust a pre-effective time payment (the “Pre-Effective Time Payment”) and term net profits interest (the “Net Profits Interest”) that together represent the right to receive 90% of the net proceeds from WOGC’s interests in certain existing oil and natural gas producing properties located in the Rocky Mountains, Permian Basin, Gulf Coast and Mid-Continent regions of the United States (the “Underlying Properties”) from January 1, 2012 until the later to occur of (i) December 31, 2021, or (ii) the time when 11.79 million stock tank barrels oil equivalent (“MMBOE”) have been produced from the Underlying Properties and sold.

It is further understood and agreed to by all parties hereto that the following transactions will occur on or before the Closing Date (as hereinafter defined):

(a) WOGC and the Trust will enter into that certain Conveyance and Assignment substantially in the form filed as Exhibit 10.1 to the Registration Statement (the “Conveyance”), pursuant to which WOGC will, among other things, convey to the Trust (i) the Pre-Effective Time Payment and (ii) the Net Profits Interest, in exchange for 18,400,000 Trust Units;

(b) WOGC will distribute the 18,400,000 Trust Units to the Company;

(c) On the Closing Date, the public offering of the Firm Units contemplated hereby will be consummated;

(d) On the Closing Date, the Trust Agreement of the Trust, by and among WOGC, The Bank of New York Mellon Trust Company, N.A., as trustee (the “Trustee”), and Wilmington Trust Company, as Delaware trustee (the “Delaware Trustee”), as amended to the date hereof (the “Organizational Trust Agreement”), shall be amended and restated, substantially in the form filed as Exhibit 3.5 to the Registration Statement (as so amended and restated, the “Trust Agreement”);

(e) On the Closing Date, WOGC and the Trust will enter into that certain Administrative Services Agreement, substantially in the form filed as Exhibit 10.2 to the Registration Statement, outlining the provision of administrative services to the Trust by WOGC and its compensation therefor (the “Administrative Services Agreement”);

(f) On the Closing Date, the Company and the Trust will enter into that certain Registration Rights Agreement, substantially in the form filed as Exhibit 10.3 to the Registration Statement, granting registration rights to the Company with respect to any Additional Units not purchased by the Underwriters in connection with the exercise of the Underwriters’ option to purchase Additional Units (the “Registration Rights Agreement”);

The transactions contemplated above are referred to herein as the “Transactions.” The “Transaction Documents” shall mean this Agreement, the Conveyance, the Administrative Services Agreement, the Derivatives Agreement and the Registration Rights Agreement.

The “Operative Agreements” shall mean the Transaction Documents, the Organizational Trust Agreement and the Trust Agreement.

Each of the Company and the Trust wishes to confirm as follows its agreement with you and the other several Underwriters, on whose behalf you are acting, in connection with the several purchases of the Units from the Company.

1. Registration Statement and Prospectus.

The Trust and the Company have prepared and filed with the Securities and Exchange Commission (the “Commission”) in accordance with the provisions of the Securities Act of 1933, as amended, and the rules and regulations of the Commission thereunder (collectively, the “Act”), a joint registration statement on Form S-1/S-3 (File No. 333-178586), including the

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related preliminary prospectus or prospectuses, relating to the Units. Such registration statement covers the registration of the Units under the Act. Promptly after execution and delivery of this Agreement, the Trust and the Company will prepare and file a prospectus in accordance with the provisions of Rule 430A (“Rule 430A”) of the Act and paragraph (b) of Rule 424 (“Rule 424(b)”) of the Act. Any information included in such prospectus that was omitted from such registration statement at the time it became effective but that is deemed to be part of and included in such registration statement pursuant to Rule 430A is referred to as “Rule 430A Information”. Each prospectus used in connection with the offering of the Units that omitted Rule 430A Information is herein called a “Preliminary Prospectus.” Such registration statement, at any given time, including the amendments thereto to such time, the exhibits and any schedules thereto at such time, the documents incorporated by reference therein pursuant to Item 12 of Form S-3 under the Act at such time and the documents otherwise deemed to be a part thereof or included therein by Act, is herein called the “Registration Statement.” The Registration Statement at the time it originally became effective is herein called the “Original Registration Statement.” The final prospectus in the form first furnished to the Underwriters for use in connection with the offering of the Units, including the documents incorporated by reference therein pursuant to Item 12 of Form S-3 under the Act at the time of the execution of this Agreement, is herein called the “Prospectus.” If the Trust and the Company file another joint registration statement with the Commission to register additional Trust Units pursuant to Rule 462(b) under the Act (the “Rule 462 Registration Statement”), then any reference to “Registration Statement” herein shall be deemed to include the registration statement on Form S-1/S-3 (File No. 333-178586) and the Rule 462 Registration Statement, as each such registration statement may be amended pursuant to the Act. For purposes of this Agreement, “free writing prospectus” has the meaning ascribed to it in Rule 405 under the Act (“Rule 405”), and “Issuer Free Writing Prospectus” shall mean each free writing prospectus prepared by or on behalf of the Company or the Trust or used or referred to by the Company or the Trust in connection with the offering of the Units. “Time of Sale Information” shall mean the most recent Preliminary Prospectus, each free writing prospectus, if any, identified in Schedule II hereto and the information set out in Schedule III hereto. All references in this Agreement to the Registration Statement, the Rule 462 Registration Statement, the Preliminary Prospectus, the Prospectus or the Time of Sale Information, or any amendments or supplements to any of the foregoing, shall be deemed to refer to and include any documents incorporated by reference therein, and shall include any copy thereof filed with the Commission pursuant to its Electronic Data Gathering, Analysis and Retrieval System (“EDGAR”). “Effective Date” means each date and time as of which any Registration Statement was or is declared effective by the Commission. “Time of Sale” means [l] [a.m./p.m.], St. Petersburg, Florida time, on [l], 2012.

2. Agreements to Sell and Purchase.

The Company hereby agrees to sell the Firm Units to the Underwriters and, upon the basis of the representations, warranties and agreements of the Company and the Trust herein contained and subject to all the terms and conditions set forth herein, each Underwriter agrees, severally and not jointly, to purchase from the Company at a purchase price of $[l] per Unit (the “purchase price per Unit”), the number of Firm Units set forth opposite the name of such Underwriter in Schedule I hereto.

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The Company hereby also agrees to sell to the Underwriters, and, upon the basis of the representations, warranties and agreements of the Company and the Trust herein contained and subject to all the terms and conditions set forth herein, the Underwriters shall have the right for 30 days from the date of the Prospectus to purchase from the Company up to 2,400,000 Additional Units at the purchase price per Unit for the Firm Units. The Additional Units may be purchased solely for the purpose of covering over-allotments, if any, made in connection with the offering of the Firm Units. If any Additional Units are to be purchased, each Underwriter, severally and not jointly, agrees to purchase the number of Additional Units (subject to such adjustments as you may determine to avoid fractional units) that bears the same proportion to the total number of Additional Units to be purchased by the Underwriters as the number of Firm Units set forth opposite the name of such Underwriter in Schedule I hereto bears to the total number of Firm Units. The option to purchase Additional Units may be exercised at any time within 30 days after the date of the Prospectus, and at the Underwriters’ election, this option may be partially exercised on more than one occasion.

3. Terms of Public Offering.

The Company and the Trust have been advised by you that the Underwriters propose to make a public offering of their respective portions of the Units as soon after the Registration Statement and this Agreement have become effective as in your judgment is advisable and initially to offer the Units upon the terms set forth in the Prospectus.

Not later than 12:00 p.m. on the second business day following the date the Units are released by the Underwriters for sale to the public, the Company shall deliver or cause to be delivered copies of the Prospectus in such quantities and at such places as the Representatives shall request.

4. Delivery of the Units and Payment Therefor.

Delivery to the Underwriters of the Firm Units and payment therefor shall be made at the offices of the Company, 1700 Broadway, Suite 2300, Denver, Colorado at 10:00 a.m., St. Petersburg, Florida time, on [l], 2012 or such other place, time and date not later than 1:30 p.m., St. Petersburg, Florida time, on [l], 2012 as the Representatives shall designate by notice to the Company and the Trust (the time and date of such closing are called the “Closing Date”). The place of closing for the Firm Units and the Closing Date may be varied by agreement among the Representatives, the Company and the Trust. The Company and the Trust hereby acknowledge that circumstances under which the Representatives may provide notice to postpone the Closing Date as originally scheduled include any determination by the Company, the Trust or the Representatives to recirculate to the public copies of an amended or supplemented Prospectus or a delay as contemplated by the provisions of Section 12 hereof.

Delivery to the Underwriters of and payment for any Additional Units to be purchased by the Underwriters shall be made at the offices of the Company, 1700 Broadway, Suite 2300, Denver, Colorado at 10:00 a.m., St. Petersburg, Florida time, on such date or dates (each an “Additional Closing Date”) (which may be the same as the Closing Date, but shall in no event be earlier than the Closing Date nor earlier than three nor later than ten business days after the giving of the notice hereinafter referred to) as shall be specified in a written notice or notices,

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from the Representatives on behalf of the Underwriters to the Company and the Trust, of the Underwriters’ determination to purchase a number, specified in such notice, of Additional Units. Such notice or notices may be given at any time within 30 days after the date of the Prospectus and must set forth (i) the aggregate number of Additional Units as to which the Underwriters are exercising the option and (ii) the names and denominations in which the certificates for which the Additional Units are to be registered. The place of closing for the Additional Units and the Additional Closing Date may be varied by agreement among the Representatives, the Company and the Trust.

Delivery of the Firm Units and of any Additional Units to be purchased hereunder shall be made through the facilities of The Depository Trust Company (“DTC”) against payment of the purchase price therefore by wire transfer of immediately available funds to an account or accounts specified in writing, not later than the close of business on the business day next preceding the Closing Date or the Additional Closing Date, as the case may be, by the Company. Payment for the Units sold by the Company hereunder shall be delivered by the Representatives to the Company.

It is understood that the Representatives have been authorized, for their own account and the accounts of the several Underwriters, to accept delivery of and receipt for, and make payment of the purchase price per Unit for the Firm Units and the Additional Units, if any, that the Underwriters have agreed to purchase. Each Representative, individually and not as a Representative of the Underwriters, may, but shall not be obligated to, make payment for any Units to be purchased by any Underwriter whose funds shall not have been received by the Representatives by the Closing Date or the Additional Closing Date, as the case may be, for the account of such Underwriter, but any such payment shall not relieve such Underwriter from any of its obligations under this Agreement.

5. Covenants and Agreements.

Each of the Company and the Trust, each as to itself, covenants and agrees with the several Underwriters as follows:

(a) Each of the Company and the Trust will use its best efforts to cause the Registration Statement and any amendments thereto to become effective, if it has not already become effective, and will advise you promptly and, if requested by you, will confirm such advice in writing (i) when the Registration Statement has become effective and the time and date of any filing of any post-effective Registration Statement or any amendment or supplement to any Preliminary Prospectus or the Prospectus and the time and date that any post-effective amendment to the Registration Statement becomes effective, (ii) if Rule 430A under the Act is employed, when the Prospectus has been timely filed pursuant to Rule 424(b) under the Act, (iii) of the receipt of any comments of the Commission, or any request by the Commission for amendments or supplements to the Registration Statement, any Preliminary Prospectus or the Prospectus or for additional information, (iv) of the issuance by the Commission of any stop order suspending the effectiveness of the Registration Statement or of the suspension of qualification of the Units for offering or sale in any jurisdiction or the initiation of any proceeding for such purposes and (v) within the period of time referred to in Section 5(h) below, of any change in the condition (financial or other), business, prospects, properties, net worth or

5

results of operations of the Company, the Trust or the Underlying Properties, or of any event that comes to the attention of the Company or the Trust that makes any statement made in the Registration Statement or the Prospectus (as then amended or supplemented) untrue in any material respect or that requires the making of any additions thereto or changes therein in order to make the statements therein (in the case of the Prospectus, in the light of the circumstances under which they were made) not misleading in any material respect, or of the necessity to amend or supplement the Prospectus (as then amended or supplemented) to comply with the Act or any other applicable law. If at any time the Commission shall issue any stop order suspending the effectiveness of the Registration Statement, the Company and the Trust will make every reasonable effort to obtain the withdrawal or lifting of such order at the earliest possible time. The Company will provide the Underwriters with copies of the form of Prospectus, in such number as the Underwriters may reasonably request, and file with the Commission such Prospectus in accordance with Rule 424(b) of the Act before the close of business on the first business day immediately following the date hereof.

(b) The Company will furnish to you, without charge, a photocopy of the signed original of the Registration Statement as originally filed with the Commission and of each amendment thereto, including financial statements and all exhibits thereto, and will also furnish to you, without charge, such number of conformed copies of the Registration Statement as originally filed and of each amendment thereto as you may reasonably request.

(c) The Company and the Trust will promptly file with the Commission any amendment or supplement to the Registration Statement or the Prospectus that may, in the judgment of the Company or the Representatives be required by the Act or requested by the Commission.

(d) The Company will furnish a copy of any amendment or supplement to the Registration Statement or to the Prospectus or any Issuer Free Writing Prospectus to the Representatives and counsel for the Underwriters and obtain your consent prior to filing any of those with the Commission, which consent shall not be unreasonably withheld or delayed.

(e) Neither the Company nor the Trust has made or will make any offer relating to the Units that would constitute an Issuer Free Writing Prospectus without your prior consent, which consent shall not be unreasonably withheld or delayed.

(f) The Company and the Trust will retain in accordance with the Act all Issuer Free Writing Prospectuses not required to be filed pursuant to the Act; and if at any time after the date hereof any events shall have occurred as a result of which any Issuer Free Writing Prospectus, as then amended or supplemented, would conflict with the information in the Registration Statement, the Preliminary Prospectus, the Time of Sale Information or the Prospectus or would include an untrue statement of a material fact or omit to state any material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading, or, if for any other reason it shall be necessary to amend or supplement any Issuer Free Writing Prospectus, to notify you and, upon your request, to file such document (if required to be filed pursuant to the Act) and to prepare and furnish without charge to each Underwriter as many copies as they may from time to time reasonably request of an amended or supplemented Issuer Free Writing Prospectus that will correct such conflict, statement or omission or effect such compliance.

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(g) Prior to the execution and delivery of this Agreement, the Company has delivered or will deliver to you, without charge, in such quantities as you have requested or may hereafter reasonably request, copies of each form of the Preliminary Prospectus. Consistent with the provisions of Section 5(h) hereof, the Company and the Trust consent to the use, in accordance with the provisions of the Act and with the securities or Blue Sky laws of the jurisdictions in which the Units are offered by the several Underwriters and by dealers, prior to the date of the Prospectus, of each Preliminary Prospectus so furnished by the Company or the Trust.

(h) As soon after the execution and delivery of this Agreement as is practicable and thereafter from time to time for such period as in the reasonable opinion of counsel for the Underwriters a prospectus is required by the Act to be delivered in connection with sales by any Underwriter or a dealer (the “Prospectus Delivery Period”), and for so long a period as you may request for the distribution of the Units, the Company will deliver to each Underwriter and each dealer, without charge, as many copies of the Prospectus and the Time of Sale Information (and of any amendment or supplement thereto) as they may reasonably request. The Company and the Trust consent to the use of the Prospectus and the Time of Sale Information (and of any amendment or supplement thereto) in accordance with the provisions of the Act and with the securities or Blue Sky laws of the jurisdictions in which the Units are offered by the several Underwriters and by all dealers to whom Units may be sold, both in connection with the offering and sale of the Units and for such period of time thereafter as the Prospectus is required by the Act to be delivered in connection with sales by any Underwriter or dealer. If at any time prior to the later of (i) the completion of the distribution of the Units pursuant to the offering contemplated by the Registration Statement or (ii) the expiration of prospectus delivery requirements with respect to the Units under Section 4(3) of the Act and Rule 174 thereunder, any event shall occur that in the judgment of the Company or in the opinion of counsel for the Underwriters is required to be set forth in the Prospectus (as then amended or supplemented) or should be set forth therein in order to make the statements therein, in the light of the circumstances under which they were made, not misleading, or if it is necessary to supplement or amend the Prospectus to comply with the Act or any other law, the Company and the Trust will forthwith prepare and, subject to Section 5(a) hereof, file with the Commission and use their best efforts to cause to become effective as promptly as possible an appropriate supplement or amendment thereto, and will furnish to each Underwriter who has previously requested Prospectuses, without charge, a reasonable number of copies thereof.

(i) If this Agreement shall terminate or shall be terminated after execution pursuant to Section 13(i) hereof or if this Agreement shall be terminated by the Underwriters because of any inability, failure or refusal on the part of the Company or the Trust to perform in all material respects any agreement herein or to comply in all material respects with any of the terms or provisions hereof or to fulfill in all material respects any of the conditions of this Agreement, the Company agrees to reimburse the Representatives and the other Underwriters, other than defaulting Underwriters, for all out-of-pocket expenses (including travel expenses and reasonable fees and expenses of counsel for the Underwriters, but excluding wages and salaries paid by the Representatives or the other Underwriters) reasonably incurred by the Representatives or the other Underwriters in connection herewith, up to a maximum aggregate amount of $300,000.

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(j) The Company will apply the net proceeds from the sale of the Units to be sold by it hereunder in accordance in all material respects with the statements under the caption “Use of Proceeds” in the Prospectus.

(k) For a period commencing on the date hereof and ending on the 180th day after the date of the Prospectus (the “Lock-Up Period”), neither the Company nor the Trust will, directly or indirectly, (i) offer for sale, sell, pledge or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) (collectively, a “Disposition”) any Trust Units, or other securities of the Trust, or other securities that are derived from the Subject Interests (as defined in the Conveyance) that are substantially similar to the Trust Units, or securities convertible into or exchangeable for Trust Units, or sell or grant options, rights or warrants with respect to any Trust Units or securities convertible into or exchangeable for Trust Units (collectively, “Trust Securities”), (ii) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of such Trust Units, whether any such transaction is to be settled by delivery of Trust Units or other securities, in cash or otherwise, (iii) file or cause to be filed a registration statement, including any amendments, with respect to the registration of any Trust Securities or (iv) publicly disclose the intention to do any of the foregoing, in each case without the prior written consent of the Representatives on behalf of the Underwriters; notwithstanding the foregoing if (x) during the last 17 days of the Lock-Up Period, the Trust issues a release concerning distributable cash or announces material news or a material event relating to the Trust occurs or (y) prior to the expiration of the Lock-Up Period, the Trust announces that it will release distributable cash results during the 16-day period beginning on the last day of the Lock-Up Period, then the restrictions imposed in this Section 5(k) shall continue to apply until the expiration of the 18-day period beginning on the date of issuance of the earnings release or the announcement of the material news or the occurrence of the material event, unless the Representatives, on behalf of the Underwriters, waives such extension in writing. In addition, this Section 5(k) shall not restrict or prohibit the Company Parties from pledging or otherwise granting a security interest with respect to any Trust Securities held by the Company Parties pursuant to that certain Fifth Amended and Restated Credit Agreement, dated as of October 15, 2010, among the Company, the financial institutions named therein and JPMorgan Chase Bank, N.A., as administrative agent, as amended (the “Credit Agreement”).

(l) The Company and the Trust will comply with all provisions of any undertakings contained in the Registration Statement.

(m) Neither the Company nor the Trust will at any time, directly or indirectly, take any action designed, or which might reasonably be expected to cause or result in, or which will constitute, stabilization or manipulation of the price of the Trust Units to facilitate the sale or resale of any of the Units in violation of the Securities Exchange Act of 1934, as amended, and the rules and regulations of the Commission thereunder (collectively, the “Exchange Act”), the Act or other applicable law.

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(n) On the Closing Date, all stock transfer and other taxes (other than income taxes) that are required to be paid in connection with the sale and transfer of the Firm Units to be sold by the Company to the Underwriters hereunder will have been fully paid for by the Company and all laws imposing such taxes will have been fully complied with.

(o) On the Additional Closing Date, all stock transfer and other taxes (other than income taxes) that are required to be paid in connection with the sale and transfer of the Additional Units to be sold by the Company to the Underwriters, if any, hereunder will have been fully paid for by the Company and all laws imposing such taxes will have been fully complied with.

(p) In order to document the Underwriters’ compliance with the reporting and withholding provisions of the Internal Revenue Code of 1986, as amended (the “Code”), and the regulations promulgated thereunder, with respect to the transactions herein contemplated, the Company shall deliver to you at least two days prior to the Closing Date and the Additional Closing Date, as the case may be, a properly completed and executed United States Treasury Department Substitute Form W-9.

(q) Not more than sixty business days following the Closing Date, the Company will file the Conveyance in the counties in the states listed on Schedule IV covering the leases covered by the Conveyance. The Company will provide to the Representatives evidence of such filings reasonably satisfactory to counsel for the Representatives as promptly as practicable following the time of such filings, and in any event not more than seventy business days following the Closing Date.

(r) The Company and the Trust will comply with all agreements and satisfy all conditions on its part to be complied with or satisfied pursuant to this Agreement on or prior to the Closing Date or the Additional Closing Date, as the case may be, and will advise the Underwriters prior to the Closing Date or the Additional Closing Date, as the case may be, if any statements to be made on behalf of the Company or the Trust, as appropriate, in the certificate contemplated by Section 9 hereof would be inaccurate if made as of the Closing Date or the Additional Closing Date, as the case may be.

(s) The Company and the Trust will cooperate with you and counsel for the Underwriters in connection with the registration or qualification of the Units for offering and sale by the several Underwriters and by dealers under the securities or Blue Sky laws of such jurisdictions as you may reasonably designate and will file such consents to service of process or other documents as may be reasonably necessary in order to effect and maintain such registration or qualification for so long as required to complete the distribution of the Units; provided that in no event shall the Company or the Trust be obligated to qualify to do business in any jurisdiction where it is not now so qualified or to take any action that would subject it to general service of process in suits, other than those arising out of the offering or sale of the Units, as contemplated by this Agreement and the Prospectus, in any jurisdiction where it is not now so subject. In the event that the qualification of the Units in any jurisdiction is suspended, the Company and the Trust shall so advise you promptly in writing. The Trustee will use its reasonable best efforts to qualify or register the Trust Units for sale in non-issuer transactions under (or obtain exemptions from the application of) the Blue Sky laws of each state where necessary to permit market

9

making transactions and secondary trading and will use its reasonable best efforts to cause the Trust to comply with such Blue Sky laws and to continue such qualifications, registrations and exemptions in effect for a period of five years after the date hereof.

(t) The Trust will timely file with the New York Stock Exchange (the “NYSE”) all documents and notices required by the NYSE of trusts that have or will issue securities that are traded on the NYSE.

(u) The Trust will engage and maintain, at its expense, a transfer agent and, if necessary under the jurisdiction of its organization or the rules of any national securities exchange on which the Trust Units will be listed, a registrar (which, if permitted by applicable laws and rules may be the same entity as the transfer agent) for the Trust Units.

(v) The Trust will make generally available to holders of the Trust Units a consolidated earnings statement (in form complying with the provisions of Rule 158 of the Act), which need not be audited, covering a 12-month period commencing after the effective date of the Registration Statement and the Rule 462 Registration Statement, if any, and ending not later than 15 months thereafter, as soon as practicable after the end of such period, which consolidated earnings statement shall satisfy the provisions of Section 11(a) of the Act.

(w) The Trust will furnish to holders of the Trust Units as soon as practicable after the end of each fiscal year an annual report (including financial statements of the Trust certified by independent public accountants) and, as soon as practicable after the end of each of the first three quarters of each fiscal year (beginning with the fiscal quarter ending after the effective date of the Registration Statement), to make available to holders of the Trust Units summary financial information of the Trust for such quarter in reasonable detail. For purposes of this Section 5(w), the Trust shall be deemed to have made available such summary financial information if such information has been filed on EDGAR

(x) During the period ending three years from the date hereof, the Trustee will cause the Trust to furnish to you and, upon your request, to each of the other Underwriters, (i) as soon as available, a copy of each proxy statement, quarterly or annual report or other report of the Trust mailed to unitholders or filed with the Commission, the NYSE or any other national securities exchange and (ii) from time to time such other information concerning the Trust as you may reasonably request. For purposes of this Section 5(x), the Trust shall be deemed to have furnished the required information if such document has been filed on EDGAR.

6. Representations and Warranties.

6.1 Of the Company and the Trust. The Company and the Trust hereby represent and warrant, jointly and severally, to each Underwriter on the date hereof, and shall be deemed to represent and warrant, jointly and severally, to each Underwriter on the Closing Date and the Additional Closing Date, as the case may be, that:

(a) Not an “Ineligible Issuer.” The Trust was not at the time of initial filing of the Registration Statement and at the earliest time thereafter that the Trust or any other offering participant made a bona fide offer (within the meaning of Rule 164(h)(2) of the Act) of the Trust Units, is not on the date hereof and will not be on the Closing Date and the Additional Closing Date, as the case may be, an “ineligible issuer” (as defined in Rule 405).

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(b) No Stop Order. No stop order suspending the effectiveness of the Registration Statement, any post-effective amendment thereto or the Rule 462 Registration Statement, if any, has been issued and no proceeding for that purpose has been initiated or, to the knowledge of the Trust or the Company, threatened by the Commission. No order preventing or suspending the use of any Preliminary Prospectus or any Issuer Free Writing Prospectus has been issued and no proceeding for that purpose has been initiated or, to the knowledge of the Trust or the Company, threatened by the Commission.

(c) Compliance as to Form. The Registration Statement conformed on the Effective Date and will conform on each of the Closing Date and the Additional Closing Date, as the case may be, and any amendment to the Registration Statement filed after the date hereof will conform in all material respects, when filed, to the requirements of the Act. The Preliminary Prospectus conformed, when filed, and the Prospectus will conform, when filed, with the Commission pursuant to Rule 424(b) and on the Closing Date and the Additional Closing Date, as the case may be, to the requirements of the Act.

(d) No Material Misstatements or Omissions in the Registration Statement. The Registration Statement did not, as of the Effective Date, contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading; provided that no representation or warranty is made as to information contained in or omitted from the Registration Statement in reliance upon and in conformity with written information furnished to the Company or the Trust by or on behalf of any Underwriter specifically for inclusion therein, which information is specified in Section 14.

(e) No Material Misstatements or Omissions in the Prospectus. The Prospectus will not, as of its date and on the Closing Date or the Additional Closing Date, as the case may be, contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided that no representation or warranty is made as to information contained in or omitted from the Prospectus in reliance upon and in conformity with written information furnished to the Company or the Trust by or on behalf of any Underwriter specifically for inclusion therein, which information is specified in Section 14.

(f) No Material Misstatements or Omissions in the Time of Sale Information. The Time of Sale Information, all considered together, did not, as of the Time of Sale, contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided that no representation or warranty is made as to information contained in or omitted from the Time of Sale Information in reliance upon and in conformity with written information furnished to the Company or the Trust by or on behalf of any Underwriter specifically for inclusion therein, which information is specified in Section 14.

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(g) No Material Misstatements or Omissions in Issuer Free Writing Prospectus. Each Issuer Free Writing Prospectus (including, without limitation, any road show that is a free writing prospectus under Rule 433), when considered together with the Time of Sale Information at the Time of Sale, did not contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading provided that no representation or warranty is made as to information contained in or omitted from an Issuer Free Writing Prospectus in reliance upon and in conformity with written information furnished to the Company or the Trust by or on behalf of any Underwriter specifically for inclusion therein, which information is specified in Section 14. Each Issuer Free Writing Prospectus conformed or will conform in all material respects to the requirements of the Act on the date of first use, and the Company and the Trust have complied with all prospectus delivery and any filing requirements applicable to such Issuer Free Writing Prospectus pursuant to the Act. Neither the Company nor the Trust has made any offer relating to the Trust Units that would constitute an Issuer Free Writing Prospectus without the prior written consent of the Representatives. Each of the Company and the Trust has retained in accordance with the Act all Issuer Free Writing Prospectuses that were not required to be filed pursuant to the Act. The Company and the Trust have taken all actions necessary so that any “road show” (as defined in Rule 433) in connection with the offering of the Trust Units will not be required to be filed pursuant to the Act.

(h) Contracts to be Described or Filed. There are no agreements, contracts, indentures, leases or other documents of the Trust which are required to be described in the Registration Statement, the Time of Sale Information or the Prospectus (or any amendment or supplement thereto) or the documents incorporated by reference therein or to be filed as exhibits thereto which have not been so described and filed as required.

(i) Market Stabilization. The Trust has not taken, nor will it take, directly or indirectly, any action that constituted, or any action designed to, or that might reasonably be expected to cause or result in or constitute, under the Exchange Act, the Act or otherwise, stabilization or manipulation of the price of the Trust Units to facilitate the sale or resale of the Trust Units or for any other purpose in violation of the Exchange Act, the Act or other applicable law.

(j) Formation, Due Qualification and Authority of the Trust. The Trust is duly organized and validly existing as a statutory trust in good standing under the laws of the State of Delaware with full power and authority to own or lease, as the case may be, its properties and to conduct its business as described in the Registration Statement, the Time of Sale Information and the Prospectus (and any amendment or supplement thereto) and is duly registered and qualified to conduct its business and is in good standing in each jurisdiction or place where the nature of its properties or the conduct of its business requires such registration or qualification, except where the failure to so register or qualify has not had or will not have a material adverse effect on the condition (financial or other), business, properties, net worth, results of operations or business prospects of the Trust or the Underlying Properties (a “Trust Material Adverse Effect”). The activities of the Trustee pursuant to the Trust Agreement will not require the appointment of an ancillary trustee in any state in which the Trust conducts its business.

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(k) Legal Proceedings. There are no legal or governmental proceedings pending or, to the knowledge of the Trustee, threatened, against the Trust or to which the Trust or any of its properties, including the Subject Interests, are subject, that are required to be described in the Registration Statement, the Time of Sale Information or the Prospectus (or any amendment or supplement thereto) but are not described as required. Except as described in the Registration Statement, the Time of Sale Information and the Prospectus, there is no action, suit, inquiry, proceeding or investigation by or before any court or governmental or other regulatory or administrative agency or commission pending or, to the knowledge of the Trustee, threatened against or involving the Trust, which might individually or in the aggregate (i) materially impair the ability of the Trust to consummate the Transactions or any other transactions provided for in this Agreement or the Transaction Documents or (ii) have a Trust Material Adverse Effect, nor to the Trustee’s knowledge, is there any basis for any such action, suit, inquiry, proceeding or investigation.

(l) No Default. The Trust is not (i) in violation of (A) its organizational documents or agreements, (B) any law, ordinance, administrative or governmental rule or regulation applicable to the Trust, the violation of which would have a Trust Material Adverse Effect or (C) any decree of any court or governmental agency or body having jurisdiction over the Trust, the violation of which would have a Trust Material Adverse Effect; or (ii) in default, breach or violation in any material respect in the performance of any obligation, agreement, covenant or condition contained in (A) any bond, debenture, note or any other evidence of indebtedness or (B) any agreement, indenture, lease or other instrument (each of (A) and (B), a “Trust Existing Instrument”) to which the Trust is a party or by which any of its properties may be bound, which default would have a Trust Material Adverse Effect or materially impair the ability of the Trust to consummate the Transactions or any other transactions provided for in this Agreement or the Transaction Documents; and there does not exist any state of facts that constitutes an “event of default” on the part of the Trust as defined in such documents or that, with notice or lapse of time or both, would constitute such an event of default, where the existence of such state of facts would have a Trust Material Adverse Effect.

(m) Enforceability of the Operative Agreements. Each of the Operative Agreements to which the Trust is a party has been duly authorized by the Trust and has been, or as of the Closing Date will be, duly executed and delivered by the Trust, as applicable, and when duly executed and delivered by the other parties thereto, will constitute a valid and legally binding agreement of the Trust, enforceable against the Trust in accordance with its terms, except to the extent enforceability may be limited by (i) the application of bankruptcy, reorganization, insolvency and other laws affecting creditors’ rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

(n) Authority and Authorization. The Trust has all requisite power and authority to execute and deliver this Agreement and to perform its obligations hereunder, including the sale of the Trust Units in accordance with and upon the terms and conditions set forth in this Agreement, the Trust Agreement, the Registration Statement, the Time of Sale Information and the Prospectus. At each of the Closing Date and the Additional Closing Date, all trust action required to be taken by the Trust, the Trustee or the Delaware Trustee for the consummation of the Transactions and any other Transactions provided for in this Agreement and the Operative Documents to which the Trust is a party shall have been validly taken.

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(o) Outstanding Trust Units. On the Closing Date, after giving effect to the Transactions, the Trust will have outstanding 18,250,500 Trust Units. Such Trust Units and the beneficial interests in the Trust represented thereby have been duly authorized for issuance by the Trust, and, when duly issued and delivered to WOGC in accordance with the Trust Agreement, the Trust Units will be duly and validly issued and outstanding, fully paid and nonassessable and are free of any preemptive or similar rights, and will constitute valid and binding obligations of the Trust entitled to the benefits of the Trust Agreement and enforceable in accordance with their terms, except as the enforceability of each may be limited by (i) the application of bankruptcy, reorganization, insolvency and other laws affecting creditors’ rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law). The Trust Units, when issued and delivered, will conform in all material respects to the description thereof contained in the Registration Statement, the Time of Sale Information and the Prospectus.

(p) No Consents. None of (i) the formation of the Trust by the execution and delivery of the Organizational Trust Agreement, (ii) the transfer of the Net Profits Interest and the Pre-Effective Time Payment by WOGC to the Trust by the execution and delivery of the Conveyance, (iii) the distribution of the 18,400,000 Trust Units by WOGC to the Company, (iv) the sale of the Units by the Company or (v) the execution, delivery or performance of this Agreement, the Organizational Trust Agreement, the Trust Agreement, the Administrative Services Agreement and the Conveyance by the Company Parties and the Trust nor the consummation by the Company Parties and the Trust of the transactions contemplated hereby (A) requires any consent, approval, authorization or other order of or registration or filing with, any court, regulatory body, administrative agency or other governmental body, agency or official (except such as may be required for the registration of the Units under the Act, the listing of the Units for trading on the NYSE, the registration of the Trust Units under the Exchange Act and compliance with the securities or Blue Sky laws of various jurisdictions, all of which will be, or have been, effected in accordance with this Agreement and except for the Financial Industry Regulatory Authority’s (“FINRA”) clearance of the underwriting terms of the offering contemplated hereby as required under FINRA’s Conduct Rules), (B) conflicts with or will conflict with or constitutes or will constitute a breach of, or a default under, the Trust’s trust agreement, or (C) violates any statute, law, regulation, ruling, filing, judgment, injunction, order or decree applicable to the Trust, except as disclosed in the Prospectus and except for such consents, approvals, authorizations, orders, registrations, filings, conflicts, breaches, defaults, liens, charges or encumbrances that will not, individually or in the aggregate, result in a Trust Material Adverse Effect.

(q) Independent Public Accountant. Deloitte & Touche LLP, the certified public accountants who have certified the financial statements of the the Trust (including the related notes thereto and supporting schedules) filed as part of the Registration Statement, the Time of Sale Information and the Prospectus (or any amendment or supplement thereto), is and was during the periods covered by such financial statements, an independent registered public accounting firm with respect to the Trust as required by the Act and the Public Company Accounting Oversight Board.

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(r) Financial Statements. The financial statements of the Trust, together with related schedules and notes, included in the Registration Statement, the Time of Sale Information and the Prospectus (and any amendment or supplement thereto), present fairly in all material respects, on the basis set forth in the Registration Statement, the Time of Sale Information and the Prospectus (and any amendment or supplement thereto), the financial condition of the Trust at the respective dates or for the respective periods to which they apply; said financial statements and related schedules and notes have been prepared in conformity with generally accepted accounting principles in the United States (“GAAP”) applied on a consistent basis throughout the periods involved. The supporting schedules, if any, included in the Registration Statement, the Time of Sale Information and the Prospectus (and any amendment or supplement thereto) present fairly in all material respects in accordance with GAAP the information required to be stated therein. The summary financial information of the Trust included in the Registration Statement, the Time of Sale Information and the Prospectus present fairly in all material respects the information shown therein and have been compiled on a basis consistent with that of the audited financial statements included in the Registration Statement. All disclosures relating to the Trust contained in the Registration Statement, the Time of Sale Information and the Prospectus (including any amendment or supplement thereto) regarding “non-GAAP financial measures” (as such term is defined by the rules and regulations of the Commission) comply in all material respects with Regulation G of the Exchange Act and Item 10 of Regulation S-K under the Act, to the extent applicable.

(s) Pro Forma Financial Statements. The pro forma financial statements of the Trust included in the Registration Statement, the Time of Sale Information and the Prospectus include assumptions that provide a reasonable basis for presenting the significant effects directly attributable to the transactions and events described therein, the related pro forma adjustments give appropriate effect to those assumptions, and the pro forma adjustments reflect the proper application of those adjustments to the historical financial statement amounts in the pro forma financial statements included in the Registration Statement, the Time of Sale Information and the Prospectus. The pro forma financial statements included in the Registration Statement, the Time of Sale Information and the Prospectus comply as to form in all material respects with the applicable accounting requirements of Regulation S-X under the Securities Act and the pro forma adjustments have been properly applied to the historical amounts in the compilation of those statements.

(t) (i) Disclosure Controls and Procedures. The Trust has established and maintains disclosure controls and procedures (to the extent required by and as such term is defined in Rule 13a-15(e) under the Exchange Act); (ii) such disclosure controls and procedures are designed to ensure that the information required to be disclosed by the Trust in the reports it files or will file or submit under the Exchange Act, as applicable, is accumulated and communicated to the Trustee to allow it timely decisions regarding required disclosure to be made and (iii) such disclosure controls and procedures are effective in all material respects to perform the functions for which they were established to the extent required by Rule 13a-15 of the Exchange Act.

(u) No Change in Internal Controls. Since the date of the most recent balance sheets of the Trust reviewed or audited by Deloitte & Touche LLP, (i) the Trust is not aware of (A) any significant deficiencies or material weaknesses in the design or operation of internal

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controls that could adversely affect the ability of the Trust to record, process, summarize and report financial data in any material respect, or (B) any fraud, whether material or not material, that involves management or other employees who have a significant role in the internal controls of the Trust, and (ii) there have been no significant changes in internal controls or in other factors that has or could significantly and adversely affect internal controls.

(v) Sarbanes-Oxley Act of 2002. There has been no failure on the part of the Trust to comply in all material respects with all applicable and effective provisions of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated in connection therewith. At each of the Closing Date and the Additional Closing Date, the Trust will be in compliance in all material respects with all applicable provisions of the Sarbanes-Oxley Act of 2002, the rules and regulations promulgated therewith and the rules of the NYSE that are effective and applicable to the Trust.

(w) No Changes Since Trust Formation. Since the date the Trust was formed through the date hereof, and except as may otherwise be disclosed in the Registration Statement, the Time of Sale Information or the Prospectus, the Trust has not (i) issued or granted any Trust Units, (ii) incurred any liability or obligation, direct or contingent except for this Agreement and the Operative Agreements and in connection with the execution of the transactions contemplated hereby or thereby, (iii) entered into any transaction not in the ordinary course of the Trust’s business or (iv) made any distribution on its equity interests.

(x) Listing. The Units have been approved for listing on the NYSE under the symbol “WHZ,” subject to official notice of issuance of the Units being sold by the Company, and upon consummation of the offering contemplated hereby the Trust will be in compliance with the designation and maintenance criteria applicable to NYSE issuers.

(y) Investment Company. The Trust is not, and after giving effect to the Transactions, will not be an “investment company” or an “affiliated person” of, or “promoter” or “principal underwriter” for, an investment company within the meaning of the Investment Company Act of 1940, as amended.

(z) Books and Records. The Trust (i) makes and keeps books, records and accounts, which, in reasonable detail, accurately and fairly reflect the transactions and dispositions of its assets and (ii) maintains a system of internal accounting controls sufficient to provide reasonable assurances that (A) transactions are executed in accordance with management’s general or specific authorization; (B) transactions are recorded as necessary to permit preparation of financial statements in conformity with GAAP and to maintain accountability for assets; (C) access to assets is permitted only in accordance with management’s general or specific authorization; and (D) the recorded accountability for assets is compared with the existing assets at reasonable intervals and appropriate action is taken with respect to any differences.

(aa) No Consent Needed for Trustee Action. The Trustee is a national banking association duly authorized and empowered to act as trustee of the Trust pursuant to the Organizational Trust Agreement and the Trust Agreement. The Delaware Trustee is a Delaware banking corporation duly authorized and empowered to act as Delaware trustee of the Trust

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pursuant to the Organizational Trust Agreement and the Trust Agreement. No consent, approval, authorization or filing is required under any law, rule or regulation of any of the states listed on Schedule IV, or of the United States of America in order to permit the Trustee to act as Trustee of the Trust.

6.2 Of the Company. The Company hereby represents and warrants to each Underwriter on the date hereof, and shall be deemed to represent and warrant to each Underwriter on the Closing Date and the Additional Closing Date, as the case may be, that:

(a) Not an “Ineligible Issuer.” The Company was not at the time of initial filing of the Registration Statement and at the earliest time thereafter that the Company or any other offering participant made a bona fide offer (within the meaning of Rule 164(h)(2) of the Act) of the Trust Units, is not on the date hereof and will not be on the Closing Date and the Additional Closing Date, as the case may be, an “ineligible issuer” (as defined in Rule 405).

(b) Incorporated Documents. The documents incorporated or deemed to be incorporated by reference in the Registration Statement and the Prospectus, at the time they were or hereafter are filed with the Commission, complied and will comply in all material respects with the requirements of the Exchange Act, and, when read together with (a) the other information in the Preliminary Prospectus included in the Registration Statement at the time the Registration Statement became effective, (b) the other Time of Sale Information at the Time of Sale and (c) the other information in the Prospectus at the Closing Date and any Additional Closing Date, did not and will not contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein (with respect to clauses (b) and (c) hereof, in light of the circumstances under which they were made) not misleading.

(c) Contracts to be Described or Filed. There are no agreements, contracts, indentures, leases or other documents of the Company Entities which are required to be described in the Registration Statement, the Time of Sale Information or the Prospectus (or any amendment or supplement thereto) or the documents incorporated by reference therein or to be filed as exhibits thereto which have not been so described and filed as required.

(d) Market Stabilization. Neither the Company nor any affiliate of the Company has taken, nor will the Company or any affiliate take, directly or indirectly, any action that constituted, or any action designed to, or that might reasonably be expected to cause or result in or constitute, under the Exchange Act, the Act or otherwise, stabilization or manipulation of the price of the Trust Units to facilitate the sale or resale of the Trust Units or for any other purpose in violation of the Exchange Act, the Act or other applicable law.

(e) Formation, Due Qualification and Authority of the Company and the Subsidiaries. Each of the Company Parties is a corporation duly organized and validly existing as a corporation in good standing under the laws of the state of its incorporation with full corporate power and authority to own, lease and operate its properties and to conduct its business as presently conducted and as described in the Registration Statement, the Time of Sale Information and the Prospectus (and any amendment or supplement thereto) and is duly registered and qualified to conduct its business and is in good standing in each jurisdiction or

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place where the nature of its properties or the conduct of its business requires such registration or qualification, except where the failure to so register or qualify has not had or will not have a material adverse effect on the condition (financial or other), business, properties, net worth, results of operations or business prospects of the Company, together with any of its subsidiaries (the “Company Entities”), taken as a whole (a “Company Material Adverse Effect”). As of the date of this Agreement, the only subsidiaries of the Company are WOGC, Whiting Programs, Inc., Shaw Resources Limited, LLC, Whiting Transpetco, GP, LLC, Whiting Transpetco, LP, LLC and Sustainable Water Resources, LLC (the “Subsidiaries”). Except as otherwise disclosed in the Registration Statement, at each of the Closing Date and any Additional Closing Date, the Company will own, directly or indirectly, 100% of the outstanding ownership interests in WOGC, free and clear of all liens, and all such ownership interests have been duly authorized and validly issued and are fully paid and nonassessable. The Subsidiaries, other than WOGC, considered in the aggregate as a single subsidiary, do not constitute a “significant subsidiary” as defined in Rule 1-02 of Regulation S-X.

(f) Legal Proceedings. There are no legal or governmental proceedings pending or, to the knowledge of the Company, threatened, against the Company Entities or to which the Company Entities or any of their properties, including the Subject Interests, are subject, that are required to be described in the Registration Statement, the Time of Sale Information or the Prospectus (or any amendment or supplement thereto) but are not described as required. Except as described in the Registration Statement, the Time of Sale Information and the Prospectus, there is no action, suit, inquiry, proceeding or investigation by or before any court or governmental or other regulatory or administrative agency or commission pending or, to the knowledge of the Company, threatened against or involving any of the Company Entities, which might individually or in the aggregate (i) materially impair the ability of the Company Parties to consummate the Transactions or any other transactions provided for in this Agreement or the Transaction Documents or (ii) have a Company Material Adverse Effect, nor to the Company’s knowledge, is there any basis for any such action, suit, inquiry, proceeding or investigation.

(g) No Default. No Company Entity is (i) in violation of (A) its organizational documents or agreements, (B) any law, ordinance, administrative or governmental rule or regulation applicable to any of the Company Entities, the violation of which would have a Company Material Adverse Effect or (C) any decree of any court or governmental agency or body having jurisdiction over any of the Company Entities, the violation of which would have a Company Material Adverse Effect; or (ii) in default, breach or violation in any material respect in the performance of any obligation, agreement, covenant or condition contained in (A) any bond, debenture, note or any other evidence of indebtedness or (B) any agreement, indenture, lease or other instrument (each of (A) and (B), a “Company Existing Instrument”) to which any of the Company Entities is a party or by which any of their properties may be bound, which default would have a Company Material Adverse Effect or materially impair the ability of the Company Parties to consummate the Transactions or any other transactions provided for in this Agreement or the Transaction Documents; and there does not exist any state of facts that constitutes an “event of default” on the part of any of the Company Entities as defined in such documents or that, with notice or lapse of time or both, would constitute such an event of default, where the existence of such state of facts would have a Company Material Adverse Effect.

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(h) Enforceability of the Operative Agreements. Each of the Operative Agreements to which a Company Party is a party has been duly authorized by the such Company Party and has been, or as of the Closing Date will be, duly executed and delivered by such Company Party, as applicable, and when duly executed and delivered by the other parties thereto will constitute a valid and legally binding agreement of such Company Party, enforceable against such Company Party in accordance with its terms, except to the extent enforceability may be limited by (i) the application of bankruptcy, reorganization, insolvency and other laws affecting creditors’ rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law). The holders of the Trust Units are entitled to the benefits of the Trust Agreement.

(i) Authority and Authorization. The Company has all requisite power and authority to execute and deliver this Agreement and to perform its obligations hereunder, including the sale of the Trust Units in accordance with and upon the terms and conditions set forth in this Agreement, the Trust Agreement, the Registration Statement, the Time of Sale Information and the Prospectus. At each of the Closing Date and the Additional Closing Date, all corporate action required to be taken by the Company Entities for the consummation of the Transactions and any other Transactions provided for in this Agreement and the Operative Documents shall have been validly taken.

(j) Authorization and Enforceability of the Conveyance. The Conveyance has been duly authorized and, when duly executed by the proper officers of WOGC and delivered by WOGC to the Trust will constitute (assuming due execution and delivery by the Trustee) a valid and binding agreement of WOGC enforceable against WOGC in accordance with its terms, except as enforceability of the Conveyance may be limited by (i) the application of bankruptcy, reorganization, insolvency and other laws affecting creditors’ rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law); the form of the Conveyance complies with the laws of each of the states in which such Conveyance is to be recorded or filed, including all applicable recording, filing and registration laws and regulations, and is adequate and sufficient to transfer title to the Net Profits Interest and the Pre-Effective Time Payment; the recording of the Conveyance in the real property records in each county where the Subject Interests are located is sufficient to impart notice of the contents thereof, and all subsequent purchasers or creditors of the Company or WOGC will be deemed to purchase with notice of and subject to such Net Profits Interest and Pre-Effective Time Payment; the Conveyance, the Net Profits Interest and the Pre-Effective Time Payment conform in all material respects to the descriptions thereof in the Prospectus; the Net Profits Interest and the Pre-Effective Time Payment described in the Prospectus are described in the Conveyance in a manner sufficient to identify the interests conveyed under the laws of each of the states listed on Schedule IV; and on the Closing Date 18,250,500 Trust Units shall have been issued by the Trust to WOGC in consideration for the conveyance by WOGC to the Trust of the Net Profits Interest and the Pre-Effective Time Payment pursuant to the Conveyance, after which such 18,250,500 Trust Units shall have been distributed by WOGC to the Company; on the Closing Date and the Additional Closing Date, as the case may be, 18,250,500 Trust Units will be issued and outstanding.

(k) Outstanding Trust Units Held by Company. On the Closing Date and each Additional Closing Date, if any, after giving effect to the Transactions (other than the Offering),

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the Company will have good and valid title to the Trust Units to be sold by it hereunder, free and clear of all liens, encumbrances, equities or claims whatsoever, and the Company has full power and authority to sell, assign, transfer and deliver such Trust Units hereunder; and, upon the delivery of such Trust Units and payment therefor pursuant hereto, good and valid title to such Trust Units, free and clear of all liens, encumbrances, equities or claims, will pass to the several Underwriters.

(l) No Consents for Conveyance. All consents, approvals, authorizations and orders necessary for the transfer of the Net Profits Interest and the Pre-Effective Time Payment to the Trust as described in the Prospectus have been obtained and such transfer has not had the effect of creating, and there does not exist, any lien, claim, encumbrance or equity of any kind in favor of any person with respect to any of the Net Profits Interest or and the Pre-Effective Time Payment except (i) to the extent such rights have been validly waived in writing or (ii) to the extent such liens, claims, encumbrances or equities, which, if asserted or exercised, would not have a material adverse effect on the value of the Trust Units.

(m) No Consents. None of (i) the formation of the Trust by the execution and delivery of the Organizational Trust Agreement, (ii) the transfer of the Net Profits Interest and the Pre-Effective Time Payment by WOGC to the Trust by the execution and delivery of the Conveyance, (iii) the distribution of the 18,400,000 Trust Units by WOGC to the Company, (iv) the sale of the Units by the Company or (v) the execution, delivery or performance of this Agreement, the Organizational Trust Agreement, the Trust Agreement, the Administrative Services Agreement and the Conveyance by the Company Parties and the Trust nor the consummation by the Company Parties and the Trust of the transactions contemplated hereby (A) requires any consent, approval, authorization or other order of or registration or filing with, any court, regulatory body, administrative agency or other governmental body, agency or official (except such as may be required for the registration of the Units under the Act, the listing of the Units for trading on the NYSE, the registration of the Trust Units under the Exchange Act and compliance with the securities or Blue Sky laws of various jurisdictions, all of which will be, or have been, effected in accordance with this Agreement and except for the Financial Industry Regulatory Authority’s (“FINRA”) clearance of the underwriting terms of the offering contemplated hereby as required under FINRA’s Conduct Rules), (B) conflicts with or will conflict with or constitutes or will constitute a breach of, or a default under, the Company’s or WOGC’s respective articles of organization or operating agreement or any agreement, indenture, lease or other instrument (including any lease or other real property interest relating to the Underlying Properties) to which any of the Company Entities is a party or by which any of their properties may be bound, (C) violates any statute, law, regulation, ruling, filing, judgment, injunction, order or decree applicable to any of the Company Entities or any of their properties or (D) results in a breach of, or default or Debt Repayment Triggering Event (as defined below) under, or results in the creation or imposition of any lien, charge or encumbrance upon any property or assets of any of the Company Entities pursuant to, or requires the consent of any other party to, any Company Existing Instrument or Trust Existing Instrument, except as disclosed in the Prospectus and except for such consents, approvals, authorizations, orders, registrations, filings, conflicts, breaches, defaults, liens, charges or encumbrances that will not, individually or in the aggregate, result in a Company Material Adverse Effect. As used herein, a “Debt Repayment Triggering Event” means any event or condition that gives, or with the giving of notice or lapse of time would give, the holder of any note, debenture or other evidence of

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indebtedness (or any person acting on such holder’s behalf) the right to require the repurchase, redemption or repayment of all or a portion of such indebtedness by any of the Company Entities.

(n) No Preemptive Rights, Registration Rights or Options. Except as described in the Registration Statement, the Time of Sale Information and the Prospectus, none of the Company Entities has outstanding and at the Closing Date and the Additional Closing Date, as the case may be, will have outstanding any options to purchase, or any warrants to subscribe for, or any securities or obligations convertible into, or any contracts or commitments to issue or sell, any Trust Units or any such warrants, convertible securities or obligations. Neither the filing of the Registration Statement nor the offering or sale of the Trust Units as contemplated by this Agreement gives rise to any rights for or relating to the registration of any Trust Securities except for those rights relating to the registration of Trust Units provided in the Registration Rights Agreement, if any.

(o) Independent Public Accountant. Deloitte & Touche LLP, the certified public accountants who have certified the financial statements of the Company and the Underlying Properties (as defined in the Conveyance) (including the related notes thereto and supporting schedules) filed as part of the Registration Statement, the Time of Sale Information and the Prospectus (or any amendment or supplement thereto), is and was during the periods covered by such financial statements, an independent registered public accounting firm with respect to the Company as required by the Act and the Public Company Accounting Oversight Board.

(p) Financial Statements. The financial statements, together with related schedules and notes, included or incorporated by reference in the Registration Statement, the Time of Sale Information and the Prospectus (and any amendment or supplement thereto), present fairly in all material respects, on the basis set forth in the Registration Statement, the Time of Sale Information and the Prospectus (and any amendment or supplement thereto), the results of operations of the Underlying Properties and the financial condition, results of operations, cash flows and changes in equity of the Company and its consolidated subsidiaries at the dates indicated and the statement of income, stockholders’ equity and cash flows of Company and its consolidated subsidiaries for the periods specified; said financial statements and related schedules and notes have been prepared in conformity with GAAP applied on a consistent basis throughout the periods involved. The supporting schedules, if any, included in the Registration Statement, the Time of Sale Information or the Prospectus (and any amendment or supplement thereto) present fairly in all material respects in accordance with GAAP the information required to be stated therein. The summary financial information included in the Prospectus present fairly in all material respects the information shown therein and have been compiled on a basis consistent with that of the audited financial statements included in the Registration Statement. All disclosures contained in the Registration Statement, the Time of Sale Information or the Prospectus (including any amendment or supplement thereto) regarding “non-GAAP financial measures” (as such term is defined by the rules and regulations of the Commission) comply in all material respects with Regulation G of the Exchange Act and Item 10 of Regulation S-K under the Act, to the extent applicable.

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(q) (i) Disclosure Controls and Procedures. The Company has established and maintains disclosure controls and procedures (to the extent required by and as such term is defined in Rule 13a-15(e) under the Exchange Act); (ii) such disclosure controls and procedures are designed to ensure that the information required to be disclosed by the Company in the reports it files or will file or submit under the Exchange Act, as applicable, is accumulated and communicated to the Company to allow it timely decisions regarding required disclosure to be made and (iii) such disclosure controls and procedures are effective in all material respects to perform the functions for which they were established to the extent required by Rule 13a-15 of the Exchange Act.

(r) No Change in Internal Controls. Since the date of the most recent balance sheets of the Company reviewed or audited by Deloitte & Touche LLP, (i) the Company is not aware of any material deficiencies in the design or operation of internal controls and (ii) there have been no significant changes in internal controls or in other factors that has or could significantly and adversely affect internal controls.

(s) No Restrictions on Payments. WOGC is not currently prohibited, directly or indirectly, from making any payments on account of the Net Profits Interest to the Trust.

(t) Sarbanes-Oxley Act of 2002. There has been no failure on the part of the Company or any members of its management team, in their capacities as such, to comply in all material respects with all applicable and effective provisions of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated in connection therewith. At each of the Closing Date and the Additional Closing Date, the Company will be in compliance in all material respects with all applicable provisions of the Sarbanes-Oxley Act of 2002, the rules and regulations promulgated therewith and the rules of the NYSE that are effective and applicable to the Company.

(u) No Material Changes. Except as disclosed in the Registration Statement, the Time of Sale Information and the Prospectus (or any amendment or supplement thereto), since the respective dates as of which information is given in the Registration Statement, the Time of Sale Information and the Prospectus, (i) none of the Company Entities has incurred any material liabilities or obligations, indirect, direct or contingent, or entered into any transaction that is not in the ordinary course of business, (ii) none of the Company Entities or the Underlying Properties has sustained any loss to its business or properties from fire, flood, windstorm, accident or other calamity, whether or not covered by insurance, that could reasonably be expected to result in a Company Material Adverse Affect, (iii) the Company is not in default under the terms of any class of capital stock of the Company or any outstanding debt obligations, (iv) there has not been any material change in the indebtedness of the Company (other than in the ordinary course of business) and (v) there has not been any material adverse change, or any development involving or that may reasonably be expected to result in a Company Material Adverse Effect, in the condition (financial or otherwise), business, properties, prospects, net worth or result of operations of the Company or the Underlying Properties.

(v) Certain Relationships and Related Party Transactions. Except as set forth in the Registration Statement, the Time of Sale Information and the Prospectus, there are no transactions with “affiliates” (as defined in Rule 405 promulgated under the Act) or any officer,

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director or security holder of the Company (whether or not an affiliate) that are required by the Act to be disclosed in the Registration Statement, the Time of Sale Information or the Prospectus. Additionally, no relationship, direct or indirect, exists between any of the Company Entities, on the one hand, and the directors, officers, stockholders, customers or suppliers of any of the Company Entities, on the other hand, that is required by the Act to be disclosed in the Registration Statement, the Time of Sale Information and the Prospectus that is not so disclosed.

(w) Investment Company. The Company is not, and after giving effect to the Transactions, will not be an “investment company” or an “affiliated person” of, or “promoter” or “principal underwriter” for, an investment company within the meaning of the Investment Company Act of 1940, as amended.

(x) Title to Properties. WOGC has and, as of the Closing Date and the Additional Closing Date, as the case may be, will have good and defensible title to the Subject Interests and, with respect to each well set forth in Exhibit B to the Supplemental Agreement, by and between WOGC and the Trustee, WOGC is (i) entitled to receive not less than the percentage set forth in such Exhibit B as the “Net Revenue Interest” of all Minerals (as defined in the Conveyance) produced, saved and marketed from such well to which such Net Revenue Interest corresponds without reduction of such interest throughout the duration of the Conveyance, except as specifically set forth in such Exhibit B, and (ii) obligated to bear the percentage of the costs and expenses relating to the maintenance, development and operation of such well not greater than the “Working Interest” shown in such Exhibit B with respect to such well, without increase throughout the duration of the Conveyance, except as specifically set forth in such Exhibit B, subject (in each case) to the (x) Permitted Encumbrances (as defined in the Conveyance and none of which in the aggregate materially adversely affect the value of the Subject Interests and do not materially interfere with the Net Profits Interest and the Pre-Effective Time Payment or the conveyance or the use made and proposed to be made of such property by the Company and WOGC) and (y) upon conveyance of the Net Profits Interest and Pre-Effective Time Payment to the Trust pursuant to the Conveyance, the Net Profits Interest and the Pre-Effective Time Payment. All contracts, agreements and underlying leases, which comprise a portion of the Subject Interests and which individually or in the aggregate are material to the Subject Interests taken as a whole, are in full force and effect, each of the Company and WOGC, as applicable, has paid all rents and other charges or amounts to the extent due and payable thereunder, is not in default under any of such underlying contracts, agreements or leases, has received no notice of default from any other party thereto and knows of no material default by any other party thereto. The working interests and net revenue interests in oil, gas and mineral leases and mineral interests that constitute a portion of the Subject Interests held by WOGC reflect in all material respects the right of WOGC to own, operate and receive production from such Subject Interests, and the care taken by the Company and WOGC with respect to acquiring or otherwise procuring such leases and mineral interests was generally consistent with standard industry practices for acquiring or procuring leases and interests therein to develop and produce such for hydrocarbons. Upon recordation and filing of the Conveyance, the Trust will have good and defensible title to the Net Profits Interest and the Pre-Effective Time Payment, free and clear of all liens, encumbrances and defects, except Permitted Encumbrances.

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(y) Reserve Engineers. The information underlying the estimates of reserves of the Company Entities, which was supplied by the Company Entities to Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”), independent petroleum engineers, for purposes of preparing the estimates of reserves attributable to of the Underlying Properties and the Net Profits Interest and the Pre-Effective Time Payment and preparing the letter (the “Reserve Report Letter”) of Cawley Gillespie, including, without limitation, production volumes, costs of operation and development, sales prices for production, agreements relating to current and future operations, sales of production and working interest and net revenue information relating to ownership interests of the Underlying Properties, was true and correct in all material respects on the dates such estimates were made and such information was supplied and was prepared in accordance with customary industry practices; other than normal production of the reserves and intervening spot market product price fluctuations described in the Registration Statement, the Time of Sale Information, or the Prospectus, none of the Company Entities is aware of any facts or circumstances that would result in an adverse change in the reserves attributable to the Underlying Properties, or the present value of future net cash flows therefrom, as described in the Registration Statement, the Time of Sale Information or the Prospectus and as reflected in the Reserve Report Letter, that would reasonably be expected to result in a Trust Material Adverse Effect; estimates of such reserves and present values of future net cash flows as described in the Registration Statement, the Time of Sale Information and the Prospectus and reflected in the Reserve Report Letter comply in all material respects with the applicable requirements of Regulation S-X and Regulation S-K under the 1933 Act. Cawley Gillespie, whose report as of December 9, 2011 is attached as Appendix A to the Prospectus, was, as of the date of such report, and is, as of the date hereof, an independent petroleum engineer with respect to the Trust and the Company Entities.

(z) Subordination of Liens. As of the Closing Date and the Additional Closing Date, as the case may be, except for Permitted Encumbrances, any and all liens or encumbrances on the Subject Interests will be subordinated to the Net Profits Interest and the Pre-Effective Time Payment and all future liens or encumbrances on the Subject Interests shall be subordinate and inferior to the Net Profits Interest and the Pre-Effective Time Payment.

(aa) Permits. The Company Entities possess such permits, licenses, approvals, consents and other authorizations (collectively, “Governmental Licenses”) issued by the appropriate federal, state, local or foreign regulatory agencies or bodies necessary to conduct the business now operated by them, except where the failure so to possess would not, singly or in the aggregate, result in a Company Material Adverse Effect; the Company Entities are in compliance with the terms and conditions of all such Governmental Licenses, except where the failure so to comply would not, singly or in the aggregate, result in a Company Material Adverse Effect; all of the Governmental Licenses are valid and in full force and effect, except when the invalidity of such Governmental Licenses or the failure of such Governmental Licenses to be in full force and effect would not, singly or in the aggregate, result in a Company Material Adverse Effect; and none of the Company Entities has received any written notice of proceedings relating to the revocation or modification of any such Governmental Licenses which, singly or in the aggregate, if the subject of an unfavorable decision, ruling or finding, would result in a Company Material Adverse Effect.

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(bb) Books and Records. The Company (i) makes and keeps books, records and accounts, which, in reasonable detail, accurately and fairly reflect the transactions and dispositions of its assets and (ii) maintain a system of internal accounting controls sufficient to provide reasonable assurances that (A) transactions are executed in accordance with management’s general or specific authorization; (B) transactions are recorded as necessary to permit preparation of financial statements in conformity with GAAP and to maintain accountability for assets; (C) access to assets is permitted only in accordance with management’s general or specific authorization; and (D) the recorded accountability for assets is compared with the existing assets at reasonable intervals and appropriate action is taken with respect to any differences.

(cc) Environmental Compliance and Review. Except as described in the Registration Statement, the Time of Sale Information and the Prospectus and except as would not, individually or in the aggregate, result in a Company Material Adverse Effect or a Trust Material Adverse Effect, (i) none of the Company Entities is in violation of any federal, state, local or foreign statute, law, rule, regulation, ordinance, code, policy or rule of common law or any judicial or administrative interpretation thereof, including any judicial or administrative order, consent, decree or judgment, relating to pollution or protection of human health, the environment (including, without limitation, ambient air, surface water, groundwater, land surface or subsurface strata) or wildlife, including, without limitation, laws and regulations relating to the release or threatened release of chemicals, pollutants, contaminants, wastes, toxic substances, hazardous substances, petroleum or petroleum products, asbestos-containing materials or mold (collectively, “Hazardous Materials”) or to the manufacture, processing, distribution, use, treatment, storage, disposal, transport or handling of Hazardous Materials (collectively, “Environmental Laws”), (ii) the Company Entities have all permits, authorizations and approvals required under any applicable Environmental Laws and are each in compliance with their requirements, (iii) there are no pending or, to the knowledge of the Company, threatened administrative, regulatory or judicial actions, suits, demands, demand letters, claims, liens, notices of noncompliance or violation, investigation or proceedings relating to any Environmental Law against the Company or any of its subsidiaries and (iv) there are no events or circumstances that would reasonably be expected to form the basis of an order for clean-up or remediation, or an action, suit or proceeding by any private party or governmental body or agency, against or affecting any of the Company Entities relating to Hazardous Materials or any Environmental Laws.

(dd) Intellectual Property. The Company Entities own or possess, or can acquire on reasonable terms, adequate patents, patent rights, licenses, inventions, copyrights, know-how (including trade secrets and other unpatented and/or unpatentable proprietary or confidential information, systems or procedures), trademarks, service marks, trade names or other intellectual property (collectively, “Intellectual Property”) necessary to carry on the business now operated by them, and none of the Company Entities has received any written notice or is otherwise aware of any infringement of or conflict with asserted rights of others with respect to any Intellectual Property or of any facts or circumstances which would render any Intellectual Property invalid or inadequate to protect the interest of the Company Entities therein, and which infringement or conflict (if the subject of any unfavorable decision, ruling or finding) or invalidity or inadequacy, singly or in the aggregate, would result in a Company Material Adverse Effect or a Trust Material Adverse Effect.

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(ee) FINRA Affiliations. No officer or director of the Company has a direct or indirect affiliation or association with any member of FINRA.

(ff) Insurance. Each of the Company Entities maintain insurance covering their properties, operations, personnel and businesses, including the Underlying Properties, that, in the Company’s reasonable judgment, insures against such losses and risks in amounts as are adequate in accordance with customary industry practices to protect the Company and its subsidiaries and their businesses and properties.

(gg) Forward-Looking Statements and Supporting Information. The statements (including the assumptions described therein) included in the Registration Statement, the Time of Sale Information and the Prospectus under the headings “Prospectus Summary,” “Risk Factors,” “Projected Cash Distributions” and “The Underlying Properties” (i) are within the coverage of Rule 175(b) under the Act to the extent such data constitute forward looking statements as defined in Rule 175(c) and (ii) were made by the Company and the Trust with a reasonable basis and reflect the Company’s good faith estimate of the matters described therein.

(hh) Accuracy of Descriptions. The statements set forth in the Prospectus under the caption “Description of the Trust Units,” insofar as they purport to constitute a summary of the terms of the Trust Units, and the statements under the captions “The Trust,” “Computation of Net Proceeds,” “Description of the Trust Agreement,” “Description of the Trust Units,” “U.S. Federal Income Tax Consequences,” “State Tax Considerations,” “ERISA Considerations” and “Underwriting,” fairly and accurately describe the provisions of the laws and documents referred to therein in all material respects.

(ii) Transfer Taxes. On the Closing Date and any Additional Closing Date, as the case may be, all stock transfer and other taxes that are required to be paid in connection with the sale of the Units to be sold by the Company to the Underwriters will have been fully paid by the Company and all laws imposing such taxes will have been complied with.

(jj) Anti-Corruption. None of the Company Entities nor, to the knowledge of the Company, any director, officer, agent, employee or affiliate of any Company Entity is aware of or has taken any action, directly or indirectly, that would result in a violation by such person of the Foreign Corrupt Practices Act of 1977, as amended, and the rules and regulations thereunder (the “FCPA”), including, without limitation, making use of the mails or any means or instrumentality of interstate commerce corruptly in furtherance of an offer, payment, promise to pay or authorization of the payment of any money, or other property, gift, promise to give, or authorization of the giving of anything of value to any “foreign official” (as such term is defined in the FCPA) or any foreign political party or official thereof or any candidate for foreign political office, in contravention of the FCPA; and each of the Company Entities and, to the knowledge of the Company, its affiliates have conducted their businesses in compliance with the FCPA.

(kk) Money Laundering Laws. Except as would not reasonably be expected to result in a Company Material Adverse Effect, the operations of the Company Entities are and have been conducted at all times in compliance with applicable financial recordkeeping and reporting requirements of the Currency and Foreign Transactions Reporting Act of 1970, as

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amended, the money laundering statutes of all jurisdictions, the rules and regulations thereunder and any related or similar rules, regulations or guidelines, issued, administered or enforced by any governmental agency (collectively, the “Money Laundering Laws”) and no action, suit or proceeding by or before any court or governmental agency, authority or body or any arbitrator involving any of the Company Entities with respect to the Money Laundering Laws is pending or, to the knowledge of the Company, threatened.

(ll) Office of Foreign Assets Control. Neither of the Company Partiesnor, to the knowledge of the Company, any director, officer, agent, employee or affiliate of either any Company Entity is currently subject to any U.S. sanctions administered by the Office of Foreign Assets Control of the U.S. Treasure Department (“OFAC”).

(mm) No Labor Disputes. No labor dispute with the employees of either Company Party exists or, to the knowledge of the Company, is imminent, that will result in a Company Material Adverse Effect.

(nn) Private Placement. The sale and issuance of 18,400,000 Trust Units to WOGC pursuant to the Conveyance is exempt from the registration requirements of the Act and securities laws of any state having jurisdiction with respect thereto, and none of the Trust, the Company or WOGC has taken or will take any action that would cause the loss of such exemption. The Trust has not issued or sold any securities that would be integrated with the offering of the Units contemplated by this Agreement pursuant to the Act or the interpretations thereof by the Commission.

Any certificate signed by any officer of the Company or the Trust and delivered to the Representatives or to counsel for the Underwriters pursuant to this Agreement shall be deemed a representation and warranty by the Company or the Trust, as applicable, to each Underwriter as to the matters covered thereby.

7. Expenses. Whether or not the transactions contemplated hereby are consummated or this Agreement becomes effective or is terminated (except as set forth in clause (xi) below), the Company agrees to pay or cause to be paid the following: (i) the fees, disbursements and expenses of the Company’s counsel and accountants in connection with the registration of the Units under the Act and all other expenses in connection with the preparation, printing and filing of the Registration Statement and the Prospectus and amendments and supplements thereto and the mailing and delivering of copies thereof and of any Preliminary Prospectus to the Underwriters and dealers; (ii) the printing or reproduction and delivery (including postage, air freight charges and charges for counting and packaging) of such copies of the Registration Statement, Prospectus, each Preliminary Prospectus, the Time of Sale Information, any Blue Sky memoranda, the Master Agreement Among Underwriters, this Agreement and all amendments or supplements to any of them, as may be reasonably requested for use in connection with the offering and sale of the Units; (iii) consistent with the provisions of Section 5(s), all expenses in connection with the qualification of the Units for offering and sale under state securities laws or Blue Sky laws, including reasonable attorneys’ fees and out-of-pocket expenses of the counsel for the Underwriters in connection therewith (provided that counsel fees in connection therewith do not exceed $5,000); (iv) the filing fees incident to securing any required review by FINRA of the fairness of the terms of the sale of the Units and the reasonable fees and disbursements of the

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Underwriters’ counsel relating thereto; (v) the fees and expenses associated with listing the Units on the NYSE; (vi) the cost of preparing unit certificates, if any; (vii) the costs and charges of any transfer agent or registrar; (viii) the cost of the tax stamps, if any, in connection with the issuance and delivery of the Units to the respective Underwriters; (ix) all other fees, costs and expenses referred to in Item 13 of the Registration Statement; (x) the transportation, lodging, graphics and other expenses incidental to the Company’s preparation for and participation in the “roadshow” for the offering contemplated hereby; and (xi) if the proposed offering is completed, a structuring fee equal to $[—] to Raymond James & Associates, Inc. for advisory services in connection with the evaluation, analysis and structuring of the Trust (plus an additional 0.50% of the aggregate public offering price of any Additional Units). Except as provided in this Section 7 and in Section 8 hereof, the Underwriters shall pay their own expenses, including the fees and disbursements of their counsel. In addition, in the event that the proposed offering is terminated for the reasons set forth in Section 5(i) hereof, the Company agrees to reimburse the Underwriters as provided in Section 5(i).

8. Indemnification and Contribution. Subject to the limitations in this paragraph, the Company and the Trust agree, jointly and severally, to indemnify and hold harmless you and each other Underwriter, the directors, officers, employees and agents of each Underwriter, and each person, if any, who controls any Underwriter within the meaning of Section 15 of the Act or Section 20 of the Exchange Act and any “affiliate” (within the meaning of Rule 405 of the Act) of such Underwriter participating in the offering of the Units from and against any and all losses, claims, damages, liabilities and expenses, including reasonable costs of investigation and attorneys’ fees and expenses (collectively, “Damages”) arising out of or based upon any untrue statement or alleged untrue statement of a material fact contained in any Preliminary Prospectus, in the Registration Statement, the Time of Sale Information, any Issuer Free Writing Prospectus or the Prospectus or in any amendment or supplement thereto, or any omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein (in the case of the Preliminary Prospectus, the Time of Sale Information, any Issuer Free Writing Prospectus or the Prospectus, in the light of the circumstances under which they were made) not misleading, except to the extent that any such Damages arise out of or are based upon an untrue statement or omission or alleged untrue statement or omission that has been made therein or omitted therefrom in reliance upon and in conformity with the information furnished in writing to the Company by or on behalf of any Underwriter expressly for use in connection therewith as set forth in Section 14 hereof; provided, however, that with respect to any untrue statement or omission made in any Preliminary Prospectus, the indemnity agreement contained in this paragraph shall not inure to the benefit of any Underwriter (or to the benefit of any person controlling such Underwriter or to any officer, director, employee or agent of any Underwriter or to any such affiliate) from whom the person asserting any such Damages purchased the Units concerned if both (A) a copy of the Time of Sale Information was not sent or given to such person at or prior to the written confirmation of the sale of such Units to such person as required by the Act and (B) the untrue statement or omission in the Preliminary Prospectus was corrected in the Time of Sale Information. This indemnification shall be in addition to any liability that the Company or the Trust may otherwise have.

In addition to their other obligations under this Section 8, the Company and Trust agree that, as an interim measure during the pendency of any claim, action, investigation, inquiry or other proceeding arising out of or based upon any statement or omission, or any inaccuracy in

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the representations and warranties of the Company or the Trust herein or failure to perform their respective obligations hereunder, all as set forth in this Section 8, the party against whom indemnification is being sought will reimburse each Underwriter on a monthly basis for all reasonable legal or other out-of-pocket expenses incurred in connection with investigating or defending any such claim, action, investigation, inquiry or other proceeding (to the extent documented by reasonably itemized invoices therefor), notwithstanding the absence of a judicial determination as to the propriety and enforceability of the obligation of the Company to reimburse each Underwriter for such expenses and the possibility that such payments might later be held to have been improper by a court of competent jurisdiction. To the extent that any such interim reimbursement payment is so held to have been improper, each Underwriter shall promptly return it to the person(s) from whom it was received.

If any action or claim shall be brought against any Underwriter or any person controlling any Underwriter in respect of which indemnity may be sought against the Company or Trust, such Underwriter or such controlling person or any affiliate (within the meaning of Rule 405 of the Act) of such Underwriter participating in the offering of the Units (each, an “indemnified party”) shall promptly notify in writing the party against whom indemnification is being sought (the “indemnifying party”), but failure to so notify an indemnifying party shall not relieve such indemnifying party from any liability hereunder to the extent it is not materially prejudiced as a result thereof and in any event shall not relieve it from any liability which it may have otherwise than on account of this Section 8, and such indemnifying party shall assume the defense thereof, including the employment of counsel reasonably acceptable to such Underwriter or such controlling person and the payment of all reasonable fees of and expenses incurred by such counsel. Such indemnified party shall have the right to employ separate counsel in any such action and participate in the defense thereof, but the fees and expenses of such counsel shall be at the expense of such indemnified party, unless (i) the indemnifying party has agreed in writing to pay such fees and expenses, (ii) the indemnifying party has failed to assume the defense and employ counsel reasonably acceptable to the indemnified party or (iii) the named parties to any such action (including any impleaded parties) include both the indemnified party and the indemnifying party, and the indemnified party shall have been advised by its counsel that one or more legal defenses may be available to the indemnified party that may not be available to the Company, or that representation of such indemnified party and any indemnifying party by the same counsel would be inappropriate under applicable standards of professional conduct (whether or not such representation by the same counsel has been proposed) due to actual or potential differing interests between them (in which case the indemnifying party shall not have the right to assume the defense of such action on behalf of such indemnified party (but the Company and the Trust, as appropriate, shall not be liable for the fees and expenses of more than one counsel (in addition to any local counsel) for the indemnified party)). It is understood that the indemnifying party shall not, in respect of the legal expenses of the indemnified party in connection with any proceeding or related proceedings in the same jurisdiction, be liable for fees and expenses of more than one separate firm (in addition to any local counsel) for all indemnified parties. In the case of any such separate firm for an indemnified party, such firm shall be designated in writing by the Representatives. The indemnifying party shall not be liable for any settlement of any such action effected without its written consent, but if settled with such written consent, or if there be a final judgment for the plaintiff in any such action, the indemnifying party agrees to indemnify and hold harmless any indemnified party from and against any loss, claim, damage, liability or expense by reason of such settlement or judgment,

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but in the case of a judgment only to the extent stated in the first paragraph of this Section 8. If at any time any Underwriter shall have requested an indemnifying party to reimburse such Underwriter for fees and expenses of counsel, such indemnifying party agrees that it shall be liable for any settlement of the nature contemplated by this paragraph effected without its written consent if (i) such settlement is entered into 45 days after receipt by such indemnifying party of the aforesaid request, (ii) such indemnifying party shall have received notice of the terms of such settlement at least 30 days prior to such settlement being entered and (iii) such indemnifying party shall not have reimbursed such Underwriter in accordance with such request prior to the date of such settlement.

Each Underwriter agrees, severally and not jointly, to indemnify and hold harmless the Trust, its trustees, the Company, its directors or its officers who sign the Registration Statement and any person who controls the Company or the Trust within the meaning of Section 15 of the Act or Section 20 of the Exchange Act, to the same extent as the foregoing several indemnity from the Company and the Trust to each Underwriter, but only with respect to information furnished in writing by or on behalf of such Underwriter expressly for use in the Registration Statement, the Prospectus, the Time of Sale Information, any Issuer Free Writing Prospectus or any Preliminary Prospectus, or any amendment or supplement thereto, which such information is specified in Section 14. If any action or claim shall be brought or asserted against the Trust, its trustees, the Company, any of its directors, any of its officers, or any such controlling person based on the Registration Statement, the Prospectus, the Time of Sale Information or any Preliminary Prospectus, or any amendment or supplement thereto, and in respect of which indemnity may be sought against any Underwriter pursuant to this paragraph, such Underwriter shall have the rights and duties given to the Company and the Trust by the immediately preceding paragraph (except that if the Trust, its trustees or the Company shall have assumed the defense thereof such Underwriter shall not be required to do so, but may employ separate counsel therein and participate in the defense thereof, but the fees and expenses of such counsel shall be at such Underwriter’s expense), and the Trust, its trustees, the Company, its directors or its officers and any such controlling persons, shall have the rights and duties given to the Underwriters by the immediately preceding and following paragraph.

In any event, the Company and the Trust will not, without the prior written consent of the Representatives, settle, compromise or consent to the entry of any judgment in any proceeding or threatened claim, action, suit or proceeding in respect of which the indemnification may be sought hereunder (whether or not the Representatives or any person who controls any Representative within the meaning of Section 15 of the Act or Section 20 of the Exchange Act is a party to such claim, action, suit or proceeding) unless such settlement, compromise or consent includes an unconditional release of all Underwriters and such controlling persons from all liability arising out of such claim, action, suit or proceeding and does not include a statement as to or an admission of fault, culpability or a failure to act by or on behalf of any Underwriter or such controlling persons.

If the indemnification provided for in this Section 8 is unavailable or insufficient for any reason whatsoever to an indemnified party in respect of any Damages referred to herein, then an indemnifying party, in lieu of indemnifying such indemnified party, shall contribute to the amount paid or payable by such indemnified party as a result of such Damages (i) in such proportion as is appropriate to reflect the relative benefits received by the Company and the

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Trust, respectively, on the one hand, and the Underwriters, on the other hand, from the offering and sale of the Units or (ii) if the allocation provided by clause (i) above is not permitted by applicable law, in such proportion as is appropriate to reflect not only the relative benefits referred to in clause (i) above but also the relative and several fault of the Company and the Trust, respectively, on the one hand, and the Underwriters, on the other hand, in connection with the statements or omissions that resulted in such Damages as well as any other relevant equitable considerations. The relative and several benefits received by the Company and the Trust, respectively, on the one hand, and the Underwriters, on the other hand, shall be deemed to be in the same proportion as the total net proceeds from the offering (before deducting expenses) received by the Company and the Trust, as the case may be, bear to the total underwriting discounts and commissions received by the Underwriters, in each case as set forth in the table on the cover page of the Prospectus (and the relative benefits received by the Trust shall be deemed to be $0); provided that, in the event that the Underwriters shall have purchased any Additional Units hereunder, any determination of the relative benefits received by the Company and the Trust or the Underwriters from the offering of the Units shall include the net proceeds (before deducting expenses) received by the Company and the Trust, and the underwriting discounts and commissions received by the Underwriters, from the sale of such Additional Units, in each case computed on the basis of the respective amounts set forth in the second table in the section of the Prospectus entitled “Underwriting.” The relative fault of the Company and the Trust, respectively, on the one hand, and the Underwriters on the other hand, shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or the omission or alleged omission to state a material fact relates to information supplied by the Company or the Trust, on the one hand, or by the Underwriters, on the other hand and the parties’ relative intent, knowledge, access to information and opportunity to correct or prevent such statement or omission.

The Company, the Trust and the Underwriters agree that it would not be just and equitable if contribution pursuant to this Section 8 was determined by a pro rata allocation (even if the Underwriters were treated as one entity for such purpose) or by any other method of allocation that does not take into account the equitable considerations referred to in the immediately preceding paragraph. The amount paid or payable by an indemnified party as a result of the Damages referred to in the immediately preceding paragraph shall be deemed to include, subject to the limitations set forth above, any legal or other expenses reasonably incurred by such indemnified party in connection with investigating or defending any such action or claim. Notwithstanding the provisions of this Section 8, no Underwriter shall be required to contribute any amount in excess of the amount of the underwriting commissions received by such underwriter in connection with the Units underwritten by it and distributed to the public. No person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Act) shall be entitled to contribution from any person who was not guilty of such fraudulent misrepresentation. The Underwriters’ obligations to contribute pursuant to this Section 8 are several in proportion to the respective numbers of Firm Units set forth opposite their names in Schedule I hereto (or such numbers of Firm Units increased as set forth in Section 12 hereof) and not joint.

Notwithstanding the second paragraph of this Section 8, any Damages for which an indemnified party is entitled to indemnification or contribution under this Section 8 shall be paid by the indemnifying party to the indemnified party as Damages are incurred after receipt of

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reasonably itemized invoices therefor. The indemnity, contribution and reimbursement agreements contained in this Section 8 and the representations and warranties of the Company and the Trust set forth in this Agreement shall remain operative and in full force and effect, regardless of (i) any investigation made by or on behalf of any Underwriter or any person controlling any Underwriter, the Company, its directors, its officers or any person controlling the Company, (ii) acceptance of any Units and payment therefor hereunder and (iii) any termination of this Agreement. A successor to any Underwriter or any person controlling any Underwriter, or to the Company, its directors, its officers or any person controlling the Company, shall be entitled to the benefits of the indemnity, contribution and reimbursement agreements contained in this Section 8.

9. Conditions of Underwriters’ Obligations. The several obligations of the Underwriters to purchase the Firm Units hereunder are subject to the following conditions:

(a) The Registration Statement shall have become effective not later than 4:00 p.m., St. Petersburg, Florida time, on the date hereof, or at such later date and time as shall be consented to in writing by the Representatives, and all filings required by Rules 424(b), 430A and 462 under the Act shall have been timely made.

(b) All corporate proceedings and other legal matters incident to the authorization, form and validity of this Agreement, the Organizational Trust Agreement, the Trust Agreement, the Administrative Services Agreement, the Conveyance, the Registration Statement, the Time of Sale Information and the Prospectus, and all other legal matters relating to this Agreement and the Transactions and any other transactions contemplated hereby shall be reasonably satisfactory in all material respects to counsel for the Underwriters, and the Company shall have furnished to such counsel all documents and information that they may reasonably request to enable them to pass upon such matters.

(c) You shall be reasonably satisfied that since the respective dates as of which information is given in the Registration Statement, the Time of Sale Information and Prospectus, (i) except as set forth or contemplated by the Registration Statement, the Time of Sale Information and the Prospectus, there shall not have been any change in the Trust Units or any material change in the indebtedness (other than in the ordinary course of business) of the Company or the Trust, (ii) except as set forth or contemplated by the Registration Statement, the Time of Sale Information and the Prospectus, no material oral or written agreement or other transaction shall have been entered into by the Company or the Trust that is not in the ordinary course of business or by the Company or the Trust that could reasonably be expected to result in a material reduction in the future earnings of the Trust, (iii) no loss or damage (whether or not insured) to the property of the Company shall have been sustained that had or could reasonably be expected to have a Material Adverse Effect or have a material adverse effect on the Subject Interests, (iv) no legal or governmental action, suit or proceeding affecting the Company or the Trust or any of its properties that could reasonably be expected to result in a Company Material Adverse Effect or a Trust Material Adverse Affect or that affects or could reasonably be expected to affect the transactions contemplated by this Agreement shall have been instituted or threatened and (v) there shall not have been any material change in the condition (financial or otherwise), business, management, results of operations or business prospects of any of the Company Parties or the Trust that makes it impractical or inadvisable in your judgment to proceed with the public offering or purchase of the Units as contemplated hereby.

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(d) You shall have received on the Closing Date (and the Additional Closing Date, if any) an opinion of Richards, Layton & Finger, P.A., special Delaware counsel to the Trust, substantially to the effect that:

(i) The Trust has been duly created and is validly existing in good standing as a statutory trust under the Delaware Statutory Trust Act, 12 Del. C. § 3801 et seq. (the “DST Act”), and all filings required under the laws of the State of Delaware with respect to the creation and valid existence of the Trust as a statutory trust have been made.

(ii) Under the DST Act and the Trust Agreement, the Trust has the trust power and authority to own property and conduct its business, all as described in the Registration Statement and the Prospectus.

(iii) Under the DST Act and the Trust Agreement, the Trust has the trust power and authority to (a) execute and deliver, and to perform its obligations under, the Underwriting Agreement and (b) issue the Trust Units and perform its obligations with respect thereto.

(iv) The Trust Agreement is a legal, valid and binding obligation of the Company and the Trustees, and is enforceable against the Company and the Trustees, in accordance with its terms.

(v) The Trust Units have been duly authorized for issuance by the Trust Agreement and, upon (i) each Person to whom a Trust Unit is to be issued by the Trust (collectively, the “Trust Unit Holders”) having been issued such Trust Unit and paid for the Trust Unit acquired by it, in accordance with the Trust Agreement and the Registration Statement, and (ii) the Trust Units having been issued and sold to the Trust Unit Holders in accordance with the Trust Agreement and the Registration Statement, the Trust Units will constitute valid and, subject to the qualifications set forth in paragraph (vi) below, fully paid and nonassessable undivided beneficial interests in the assets of the Trust.

(vi) Neither the execution, delivery and performance by the Trust of the Underwriting Agreement and the issuance of the Trust Units, nor the consummation by the Trust of any of the Transactions, requires the consent or approval of, the withholding of objection on the part of, the giving of notice to, the filing, registration or qualification with, or the taking of any other action in respect of, any governmental authority or agency of the State of Delaware, other than the filing of the Certificate of Trust with the Secretary of State of the State of Delaware pursuant to the Trust Agreement.

(vii) The Trust Unit Holders, as beneficial owners of the Trust, are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit organized under the General Corporation Law of the State of Delaware. We note that the Trust Unit Holders may be obligated to make payments as set forth in the Trust Agreement.

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In rendering such opinion, counsel may rely, to the extent they deem such reliance proper, as to matters of fact upon certificates of officers of the Company and of government officials, provided that counsel shall state their belief that they and you are justified in relying thereon. Copies of all such certificates shall be furnished to you and your counsel on the Closing Date and the Additional Closing Date, as the case may be.

(e) You shall have received on the Closing Date (and the Additional Closing Date, if any) an opinion of Foley & Lardner LLP, counsel to the Company and WOGC, substantially to the effect that:

(i) The Company has been duly incorporated and is validly existing as a corporation in good standing under the laws of the State of Delaware.

(ii) The Company is duly qualified as a foreign corporation to transact business and is in good standing in each jurisdiction in which such qualification is required, whether by reason of the ownership or leasing of property or the conduct of business, except where the failure so to qualify or to be in good standing would not result in a Company Material Adverse Effect or a Trust Material Adverse Effect.

(iii) The Company has corporate power and authority to own, lease and operate its properties and to conduct its business as described in the Prospectus and to enter into and perform its obligations under this Agreement.

(iv) WOGC has all requisite corporate power and authority to enter into the Organizational Trust Agreement, the Trust Agreement and the Administrative Services Agreement. Each of the Organizational Trust Agreement, the Trust Agreement and the Administrative Services Agreement has been duly authorized, executed and delivered by WOGC. Each of the Organizational Trust Agreement, the Trust Agreement and the Administrative Services Agreement is a valid and binding agreement of WOGC, enforceable against WOGC in accordance with its terms, except as to the extent enforceability may be limited by (A) the application of bankruptcy, reorganization, insolvency (including, without limitation, all laws relating to fraudulent transfers), moratorium or other laws relating to or affecting creditors’ rights generally and (B) equitable principles being applied at the discretion of a court before which any proceeding may be brought (regardless of whether enforcement is considered in a proceeding at equity or law), and except as rights to indemnity and contribution thereunder may be limited by federal or state securities laws, as to which we express no opinion.

(v) The Conveyance has been duly authorized, executed and delivered by WOGC.

(vi) The Company has duly authorized the sale of the Units to be sold by the Company to the Underwriters pursuant to this Agreement.

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(vii) This Agreement has been duly authorized, executed and delivered by the Company.

(viii) No filing with, or authorization, approval, consent, license, registration, qualification or decree of, any domestic court or regulatory body, administrative agency or other governmental body, agency or official having jurisdiction over the Company or any of its properties (together, the “Consents”) is required on the part of the Company for the valid sale of the Units to the Underwriters under this Agreement, the execution, delivery and performance of this Agreement, the Organizational Trust Agreement, the Trust Agreement or the Administrative Services Agreement or the consummation of the transactions contemplated hereby and thereby, except for such Consents (i) as required under the Act or the Exchange Act and the rules and regulations thereunder and state securities or “Blue Sky” laws or under the rules and regulations of FINRA, as to which such counsel need not express an opinion, (ii) which have been, or prior to the Closing Date will be, obtained, or (iii) which, if not obtained, would not, individually or in the aggregate, have a Company Material Adverse Effect or a Trust Material Adverse Effect.

(ix) None of (i) the offer, sale or delivery of the Units by the Company, (ii) the execution, delivery or performance by the Company of this Agreement, the Organizational Trust Agreement, the Trust Agreement or the Administrative Services Agreement, or (iii) the consummation by the Company of the Transactions, (A) constitutes or will constitute a breach of, or a default under, any agreement identified in Schedule I to this opinion or (B) violates or will result in any violation of the laws of any state or federal law having jurisdiction over the Company or any of its properties, except in all cases for any breach, default or violation that would not reasonably be expected to have a Company Material Adverse Effect; provided, however, that for purposes of this Section 9(e)(ix), such counsel need not express any opinion with respect to federal or state securities laws or other antifraud laws.

(x) To such counsel’s knowledge, there is no agreement, contract, indenture, lease or other instrument to which the Company or the Trust is a party that is required to be described in the Registration Statement or the Prospectus or to be filed as an exhibit to the Registration Statement that is not described or filed as required by the Securities Act.

(xi) The Registration Statement has been declared effective by the Commission under the Act. To the knowledge of such counsel, no stop order suspending the effectiveness of the Registration Statement has been issued under the Act and no proceedings for such purpose have been instituted or are pending by the Commission. Any required filing of the Prospectus and any supplement thereto pursuant to Rule 424(b) under the Act has been made in the manner and within the time period required by such Rule 424(b).

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(xii) The Registration Statement, including any Rule 462 Registration Statement, the Prospectus and each amendment or supplement to the Registration Statement and the Prospectus, as of their respective effective or issue dates (except for the financial statements and notes and the schedules thereto and the auditor’s report thereon, the oil and gas reserve data and the other financial, statistical and accounting data included therein or in exhibits to or excluded from the Registration Statement, as to which such counsel need not express any opinion) each appeared on its face appropriately responsive in all material respects to the requirements of the Act.

(xiii) The Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K and other documents and exhibits filed pursuant to the Exchange Act that are incorporated by reference into the Registration Statement, including any Rule 462 Registration Statement, the Prospectus and each amendment or supplement to the Registration Statement and the Prospectus (except for the financial statements and notes and the schedules thereto and the auditor’s reports thereon, the oil and gas reserve data and the other financial, statistical and accounting data included therein or in exhibits to or excluded from such documents, as to which such counsel need not express any opinion) each appeared on its face to comply as to form in all material respects with the requirements of the Exchange Act.

(xiv) Neither the Company nor the Trust is an “investment company” as such term is defined in the Investment Company Act of 1940, as amended.

(xv) The Units have been approved for listing on the New York Stock Exchange.

(xvi) The statements (A) in the Time of Sale Information and the Prospectus under the captions “The Trust,” “Computation of Net Proceeds,” “Description of the Trust Agreement,” “Description of the Trust Units,” “Federal Income Tax Considerations” and “ERISA Considerations” and (B) in Item 14 of the Registration Statement, insofar as such statements constitute a description of contracts or legal proceedings or refer to statements of law or legal conclusions, have been reviewed by such counsel and are accurate descriptions in all material respects of the legal matters described therein.

(xvii) Assuming the sale of the Additional Units by the Company as described in the Prospectus, the Additional Units are fungible, for federal income tax purposes, with the Firm Units.

(xviii) Upon the registration by American Stock Transfer & Trust Company, LLC (acting as transfer agent for the Trust) (the “Transfer Agent”) of the Firm Units in the name of Cede & Co. (as nominee for DTC) as the owner of such Firm Units, the crediting by DTC (acting in its capacity as a “securities intermediary” within the meaning of Section 8-102(a)(14) of the Uniform Commercial Code of the State of New York (the “NYUCC”)) by means of book entry of the Firm Units to the securities accounts (within the meaning of Section 8-501(a) of the NYUCC) of the Underwriters maintained with DTC (the “Securities Accounts”), and the payment of the purchase price

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for the Firm Units pursuant to this Agreement, and assuming that neither DTC nor any Underwriter has “notice of an adverse claim” (within the meaning of Section 8-105 of the NYUCC), each of the Underwriters will acquire a valid “security entitlement” (within the meaning of Section 8-102(a)(17) of the NYUCC) to the Firm Units so credited to such Underwriter’s Securities Account, free of any “adverse claim” (within the meaning of Section 8-102(a)(1) of the NYUCC) to the securities underlying such security entitlement, whether framed in conversion, replevin, constructive trust, equitable lien, or other theory.

(xix) Upon the registration by the Transfer Agent of the Additional Units in the name of Cede & Co. (as nominee for DTC) as the owner of such Additional Units, the crediting by DTC (acting in its capacity as a “securities intermediary” within the meaning of Section 8-102(a)(14) of the NYUCC) by means of book entry of the Additional Units to the Securities Accounts, and the payment of the purchase price for the Additional Units pursuant to this Agreement, and assuming that neither DTC nor any Underwriter has “notice of an adverse claim” (within the meaning of Section 8-105 of the NYUCC), each of the Underwriters will acquire a valid “security entitlement” (within the meaning of Section 8-102(a)(17) of the NYUCC) to the Additional Units so credited to such Underwriter’s Securities Account, free of any “adverse claim” (within the meaning of Section 8-102(a)(1) of the NYUCC) to the securities underlying such security entitlement, whether framed in conversion, replevin, constructive trust, equitable lien, or other theory.

In rendering such opinion, counsel may rely, to the extent they deem such reliance proper, as to matters of fact upon certificates of officers of the Company and of government officials, provided that counsel shall state their belief that they and you are justified in relying thereon. Copies of all such certificates shall be furnished to you and your counsel on the Closing Date and the Additional Closing Date, as the case may be. In rendering such opinion, counsel may, as to all matters governed by laws of jurisdictions other than the laws of the States of New York and Wisconsin, the federal law of the United States and the General Corporation Law of the State of Delaware, assume that the applicable laws of such other jurisdictions are identical in all relevant respects to the substantive laws of the State of Wisconsin.

In addition to the opinion set forth above, such counsel shall provide a separate letter stating that such counsel has participated in conferences with officers and employees of the Company, with representatives of the independent registered public accounting firm and independent engineering firm of the Company, and with representatives of and counsel for the Underwriters, at which the contents of the Registration Statement and the Prospectus were discussed, and although such counsel did not independently verify such information, and is not passing upon and does not assume any responsibility for, the accuracy, completeness or fairness of the statements contained in the Registration Statement or Prospectus (except to the extent set forth in paragraph (xvi) above), on the basis of the foregoing, no facts have come to such counsel’s attention that lead such counsel to believe that (i) the Registration Statement (except for the financial statements and schedules, the notes thereto and the auditors’ reports thereon, the oil and gas reserve data, the other financial, statistical and accounting data included therein or omitted therefrom and the exhibits thereto, as to which such counsel has not been asked to comment), as of the Effective Date, contained an untrue statement of a material fact or omitted to

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state a material fact required to be stated therein or necessary to make the statements therein not misleading, (ii) the Time of Sale Information (except for the financial statements and schedules, the notes thereto and the auditors’ reports thereon, the oil and gas reserve data, the other financial, statistical and accounting data included therein or omitted therefrom and the exhibits thereto, as to which such counsel has not been asked to comment), as of the Time of Sale, contained an untrue statement of a material fact or omitted to state a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading and (iii) the Prospectus (except for the financial statements and schedules, the notes thereto and the auditors’ reports thereon, the oil and gas reserve data, the other financial, statistical and accounting data included therein or omitted therefrom and the exhibits thereto, as to which such counsel has not been asked to comment), as of its issue date and as of the Closing Date or the Additional Closing Date, as the case may be, contained or contains an untrue statement of a material fact or omitted or omits to state a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading.

(f) You shall have received on the Closing Date (and the Additional Closing Date, if any) an opinion from each of Holland & Hart LLP, Butler, Snow, O’Mara, Stevens & Canada PLLC, Modrall, Sperling, Roehl, Harris & Sisk, P.A., Crowley Fleck, PLL and Cotton Bledsoe Tighe & Dawson, P.C. local counsel to the Company in the state listed opposite such counsel’s name on Schedule V, substantially to the effect that:

(i) The form of the Conveyance to be filed is adequate and sufficient under the laws of the applicable state or states to transfer title to the Net Profits Interest and the Pre-Effective Time Payment to the Trust and complies with the laws of the applicable state relating to recording, filing and registration laws and regulations; the recording of the Conveyance in the appropriate real property records in each county in the applicable state where the Subject Interests are located is sufficient to provide the Trust the protections afforded under the recordation laws of the applicable state against purchasers or creditors of the Company subsequently acquiring interests in the Subject Interests, and such purchasers and creditors of the Company will be deemed to purchase with notice of, and subject to, such Net Profits Interest and Pre-Effective Time Payment and the Conveyance and the related Net Profits Interest and Pre-Effective Time Payment should not constitute executory contracts as such term is used in the federal bankruptcy code; the Company is not required to make any recordings or filings of the Conveyance under the laws of the applicable state other than those recordings or filings described in the immediately preceding clause.

(ii) Neither the Trust nor the Trustee is required to qualify to transact business or appoint an agent for service of process in the applicable state as a result of the ownership, operation or activities of the Trust or the Trustee with respect to the Trust, and the activities of the Trustee pursuant to the Trust Agreement will not require the appointment of an ancillary trustee in the applicable state.

(iii) A beneficial owner of a Trust Unit will not be subject to personal liability under state and local laws in the applicable state or states by virtue of said ownership, including liability regulating the discharge of materials into the environment or otherwise relating to the protection of the environment.

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(iv) The execution, delivery and performance by the Trustee of the Trust Agreement will not violate or conflict with any law, administrative ruling or regulation of the applicable state.

(v) No consent, approval, authorization or filing is required under any law, rule or regulation of the applicable state (A) to permit the Trustee to act as trustee with respect to the Net Profits Interest and the Pre-Effective Time Payment or (B) in connection with the execution and delivery of the Conveyance, or is necessary to ensure the validity, legality or enforceability of the Conveyance.

In rendering such opinion, counsel may rely, to the extent they deem such reliance proper, as to matters of fact upon certificates of officers of the Company and of government officials, provided that counsel shall state their belief that they and you are justified in relying thereon. Copies of all such certificates shall be furnished to you and your counsel on the Closing Date and the Additional Closing Date, as the case may be.

(g) You shall have received on the Closing Date (and the Additional Closing Date, if any) an opinion from Holland & Hart LLP substantially to the effect that, assuming the due authorization, execution and delivery thereof by WOGC and the Trustee, the Conveyance is a valid and legally binding agreement of WOGC, enforceable against WOGC in accordance with its terms, except as to the extent enforceability may be limited by (A) the application of bankruptcy, reorganization, insolvency (including, without limitation, all laws relating to fraudulent transfers), moratorium or other laws relating to or affecting creditors’ rights generally and (B) equitable principles being applied at the discretion of a court before which any proceeding may be brought (regardless of whether enforcement is considered in a proceeding at equity or law), and except as rights to indemnity and contribution thereunder may be limited by federal or state securities laws, as to which such counsel may express no opinion.

(h) You shall have received on the Closing Date (and the Additional Closing Date, if any) an opinion of Bruce R. DeBoer, Vice President, General Counsel and Corporate Secretary of the Company, substantially to the effect that:

(i) Each Subsidiary has been duly incorporated and is validly existing as a corporation in good standing under the laws of the jurisdiction of its incorporation, has corporate power and authority to own, lease and operate its properties and to conduct its business as described in the Prospectus and is duly qualified as a foreign corporation to transact business and is in good standing in each jurisdiction in which such qualification is required, whether by reason of the ownership or leasing of property or the conduct of business, except where the failure so to qualify or to be in good standing would not result in a Material Adverse Effect. Except as otherwise disclosed in the Registration Statement, all of the issued and outstanding capital stock of each Subsidiary has been duly authorized and validly issued, is fully paid and non-assessable and, to the best of such counsel’s knowledge, is owned by the Company, directly or through subsidiaries, free and clear of any security interest, mortgage, pledge, lien, encumbrance,

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claim or equity; and, to the best of such counsel’s knowledge, none of the outstanding shares of capital stock of any Subsidiary was issued in violation of the preemptive or similar rights of any securityholder of such Subsidiary.

(ii) To the best of such counsel’s knowledge, there is not pending or threatened any action, suit, proceeding, inquiry or investigation, to which the Company or any subsidiary of the Company is a party, or to which the property of the Company or any subsidiary of the Company is subject, before or brought by any domestic court or governmental agency or body, which would reasonably be expected to result in a Company Material Adverse Effect, or which would reasonably be expected to materially and adversely affect the properties or assets thereof or the consummation of the transactions contemplated in this Agreement or the performance by the Company or the Trust of their respective obligations hereunder.

(iii) All descriptions in the Registration Statement of contracts and other documents to which the Company or any of its subsidiaries are a party are, to the best of such counsel’s knowledge, accurate in all material respects; to the best of such counsel’s knowledge, there are no franchises, contracts, indentures, mortgages, loan agreements, notes, leases or other instruments required to be described or referred to in the Registration Statement or to be filed as exhibits to the Registration Statement other than those described or referred to therein or filed as exhibits thereto.

(iv) The information in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011 as filed with the Commission on February [23], 2012 under “Business—Title to Properties” and “Legal Proceedings,” to the extent that it constitutes matters of law, summaries of legal matters or legal proceedings, or legal conclusions, has been reviewed by me and is correct in all material respects.

(v) The execution, delivery and performance of this Agreement, the Organizational Trust Agreement, the Conveyance, the Trust Agreement or the Administrative Services Agreement and the consummation of the transactions contemplated in this Agreement and in the Registration Statement (including the offering, issuance and sale of the Units pursuant to this Agreement) and compliance by the Company with its obligations under this Agreement do not and will not, whether with or without the giving of notice or lapse of time or both, conflict with or constitute a breach of, or default or Debt Repayment Triggering Event under or result in the creation or imposition of any lien, charge or encumbrance upon any property or assets of the Company or any subsidiary of the Company pursuant to any contract, indenture, mortgage, deed of trust, loan or credit agreement, note, lease or any other agreement or instrument, known to me, to which the Company or any subsidiary of the Company is a party or by which it or any of them may be bound, or to which any of the property or assets of the Company or any subsidiary of the Company is subject (except for such conflicts, breaches, defaults or Debt Repayment Triggering Events or liens, charges or encumbrances that would not have a Company Material Adverse Effect).

In rendering such opinion, such counsel may rely, as to matters of fact (but not as to legal conclusions), to the extent he deems proper, on certificates of responsible officers of the

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Company and public officials. In giving such opinion such counsel may, as to all matters governed by the laws of jurisdictions other than the law of the State of Colorado, the federal law of the United States, and the General Corporation Law of the State of Delaware, assume that the applicable laws of such other jurisdictions are identical in all relevant respects to the substantive laws of the State of Colorado. Such opinion shall not state that it is to be governed or qualified by, or that it is otherwise subject to, any treatise, written policy or other document relating to legal opinions, including, without limitation, the Legal Opinion Accord of the ABA Section of Business Law (1991).

(i) You shall have received on the Closing Date or Additional Closing Date, as the case may be, an opinion of Vinson & Elkins L.L.P., as counsel for the Underwriters, dated the Closing Date or Additional Closing Date, as the case may be, with respect to the sale of the Units, the Registration Statement and other related matters as you may reasonably request, and the Company and its counsel shall have furnished to your counsel such documents as they may reasonably request for the purpose of enabling them to pass upon such matters.

(j) You shall have received on the Closing Date or Additional Closing Date, as the case may be, a certificate of the Trustee, dated the Closing Date or Additional Closing Date, as the case may be, executed by a duly authorized officer of the Trustee, representing and warranting to each of the Underwriters that:

(i) The Trustee is a national banking association authorized and empowered to act as trustee of the Trust pursuant to the Trust Agreement, and no consent, approval, authorization or filing is required under any law, rule or regulation of the State of Delaware or of the United States of America in order to permit the Trustee to act as trustee of the Trust;

(ii) The representations and warranties of the Trust contained in this Agreement are true and correct as of such Closing Date or Additional Closing Date;

(iii) The Trust Agreement has been executed and delivered by the Trustee and, assuming the due authorization, execution and delivery thereof by WOGC and the Delaware Trustee, is a valid and binding obligation of the Trustee, enforceable against the Trustee in accordance with its terms, except as the enforceability thereof may be limited by (A) the application of bankruptcy, reorganization, insolvency, fraudulent transfer, moratorium or other laws affecting creditors’ rights generally and (B) by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law); and the Operative Agreements to which the Trust is a party have been duly and validly executed by the Trustee;

(iv) There are 18,400,000 Trust Units authorized and outstanding under the Trust Agreement, all of which have been duly and validly issued in accordance with the Trust Agreement; and holders of the Trust Units are entitled to the benefits of the Trust Agreement;

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(v) The Trust has complied with all of the agreements and satisfied all of the conditions on the part of the Trust to be performed or satisfied hereunder on or before such Closing Date or Additional Closing Date; and

(vi) No order suspending the effectiveness of the Registration Statement or the qualification or registration of the Units under the securities or Blue Sky laws of any jurisdiction shall be in effect and no proceeding for such purpose shall be pending or, to the knowledge of the Trust, threatened or contemplated by the authorities of any jurisdiction.

(k) You shall have received letters addressed to you and dated the date hereof and the Closing Date or the Additional Closing Date, as the case may be, from the firm of Deloitte & Touche LLP, independent certified public accountants, substantially in the forms heretofore approved by you, concerning statements and information of the type ordinarily included in accountants’ “comfort letters” to underwriters with respect to the financial statements and certain financial information contained in the Registration Statement, the Time of Sale Information and the Prospectus; provided that the letter delivered on the date hereof shall use a “cut off date” within three business days of the date hereof and each letter delivered on the Closing Date or any Additional Closing Date shall use a “cut off date” within two business days of such date.

(l) (i) No stop order suspending the effectiveness of the Registration Statement shall have been issued by the Commission and no proceedings for that purpose shall be pending or, to the knowledge of the Company or the Trust, shall be threatened or contemplated by the Commission at or prior to the Closing Date or Additional Closing Date, as the case may be; (ii) no order suspending the effectiveness of the Registration Statement or the qualification or registration of the Units under the securities or Blue Sky laws of any jurisdiction shall be in effect and no proceeding for such purpose shall be pending or, to the knowledge of the Company or the Trust, threatened or contemplated by the authorities of any jurisdiction; (iii) any request for additional information on the part of the staff of the Commission or any such authorities shall have been complied with to the satisfaction of the staff of the Commission or such authorities; (iv) after the date hereof, no amendment or supplement to the Registration Statement or the Prospectus or any Free Writing Prospectus shall have been filed unless a copy thereof was first submitted to you and you did not object thereto in good faith; (v) all of the representations and warranties of the Company and the Trust contained in this Agreement shall be true and correct in all material respects (except for such representations and warranties qualified by materiality, which representations and warranties shall be true and correct in all respects) on and as of the date hereof and on and as of the Closing Date or Additional Closing Date, as the case may be, as if made on and as of the Closing Date or Additional Closing Date, as the case may be, and you shall have received a certificate, dated the Closing Date or the Additional Closing Date, as the case may be, and signed by the chief executive officer and the chief financial officer of the Company (or such other officers as are acceptable to you) to the effect set forth in this Section 9(l) and in Sections 9(c) and 9(m) hereof.

(m) Neither the Company nor the Trust shall have failed in any material respect at or prior to the Closing Date or the Additional Closing Date, as the case may be, to have performed or complied with any of its agreements herein contained and required to be performed or complied with by it hereunder at or prior to the Closing Date or Additional Closing Date, as the case may be.

42

(n) At or prior to the effective date of the Registration Statement, you shall have received a letter from the Corporate Financing Department of FINRA confirming that such Department has determined to raise no objections with respect to the fairness or reasonableness of the underwriting terms and arrangements of the offering contemplated hereby.

(o) You shall have received letters addressed to you and dated the date hereof and the Closing Date or the Additional Closing Date, as the case may be, from Cawley Gillespie stating the conclusions and findings of such firm with respect to oil and gas reserves of the Company relating to the Subject Interests, substantially in the form approved by you.

All such opinions, certificates, letters and other documents will be in compliance with the provisions hereof only if they are reasonably satisfactory in form and substance to you and your counsel.

The several obligations of the Underwriters to purchase Additional Units hereunder are subject to the satisfaction on and as of the Additional Closing Date of the conditions set forth in this Section 9, except that, if the Additional Closing Date is other than the Closing Date, the certificates, opinions and letters referred to in this Section 9 shall be dated as of the Additional Closing Date, the opinions called for by paragraph (f) that were delivered on the Closing Date shall contemplate and cover such Additional Units and the opinions called for by paragraphs (d), (e) and (g) shall be revised to reflect the sale of Additional Units. In addition, the several obligations of the Underwriters to purchase Additional Units hereunder are subject to the receipt of certificates dated the Additional Closing Date from the Company and the Trust to the effect that, as of the Additional Closing Date: (i) the representations and warranties made by the Company and the Trust herein are true and correct in all material respects and (ii) the Company and the Trust have complied with all obligations and satisfied all conditions that are required to be performed or satisfied on its part at or prior to the Additional Closing Date.

If any of the conditions hereinabove provided for in this Section 9 shall not have been satisfied when and as required by this Agreement, this Agreement may be terminated by you by notifying the Company of such termination in writing at or prior to such Closing Date, but you shall be entitled to waive any of such conditions.

10. Effective Date of Agreement. This Agreement shall become effective upon the later of (a) the execution and delivery hereof by the parties hereto and (b) release of notification of the effectiveness of the Registration Statement by the Commission; provided, however, that the provisions of Sections 7 and 8 shall at all times be effective.

11. Use of Free Writing Prospectus. Each Underwriter severally covenants with the Company that it has not made and will not make any offer relating to the Units that would constitute a “free writing prospectus,” as defined in Rule 405 under the Act, required to be filed with the Commission without the consent of the Company, not to be unreasonably withheld, other than any such offer included in an Issuer Free Writing Prospectus. The Company and the Trust covenant with the Underwriters that they have not made and will not make any offer

43

relating to the Units that would constitute a “free writing prospectus,” as defined in Rule 405 under the Act, required to be filed with the Commission without the consent of the Representatives, not to be unreasonably withheld, other than any such offer included in an Issuer Free Writing Prospectus included in the Time of Sale Information.

12. Defaulting Underwriters. If any one or more of the Underwriters shall fail or refuse to purchase Firm Units that it or they have agreed to purchase hereunder, and the aggregate number of Firm Units that such defaulting Underwriter or Underwriters agreed but failed or refused to purchase is not more than one-tenth of the aggregate number of the Firm Units, each non-defaulting Underwriter shall be obligated, severally, in the proportion in which the number of Firm Units set forth opposite its name in Schedule I hereto bears to the aggregate number of Firm Units set forth opposite the names of all non-defaulting Underwriters or in such other proportion as you may specify in the Agreement Among Underwriters, to purchase the Firm Units that such defaulting Underwriter or Underwriters agreed, but failed or refused to purchase. If any Underwriter or Underwriters shall fail or refuse to purchase Firm Units and the aggregate number of Firm Units with respect to which such default occurs is more than one-tenth of the aggregate number of Firm Units and arrangements satisfactory to you and the Company for the purchase of such Firm Units are not made within 48 hours after such default, this Agreement will terminate without liability on the part of any non-defaulting Underwriter or the Company. In any such case that does not result in termination of this Agreement, either you or the Company shall have the right to postpone the Closing Date, but in no event for longer than seven (7) days, in order that the required changes, if any, in the Registration Statement and the Prospectus or any other documents or arrangements may be effected. Any action taken under this paragraph shall not relieve any defaulting Underwriter from liability in respect of any such default of any such Underwriter under this Agreement.

13. Termination of Agreement. The Representatives may terminate this Agreement, by notice to the Company, at any time at or prior to Closing Date or the Additional Closing Date (if different from the Closing Date and then only as to the Additional Units) (i) if there has been, since the time of execution of this Agreement or since the respective dates as of which information is given in the Prospectus (exclusive of any amendment or supplement thereto subsequent to the date of this Agreement) or the Time of Sale Information, any material adverse change in the condition, financial or otherwise, or in the earnings, business affairs or business prospects of the Company Entities considered as one enterprise, whether or not arising in the ordinary course of business, or (ii) if there has occurred after the date hereof and prior to the Closing Date or the Additional Closing Date, as applicable, any material adverse change in the financial markets in the United States or the international financial markets, any outbreak of hostilities or escalation thereof or other calamity or crisis or any change or development involving a prospective change in national or international political, financial or economic conditions, in each case the effect of which is such as to make it, in the reasonable judgment of the Representatives, impracticable or inadvisable to market the Units or to enforce contracts for the sale of the Units, or (iii) if trading in any securities of the Company has been suspended or materially limited by the Commission or the New York Stock Exchange, or if trading generally on the American Stock Exchange or the New York Stock Exchange or in the Nasdaq Stock Market has been suspended or materially limited, or minimum or maximum prices for trading have been fixed, or maximum ranges for prices have been required, by any of said exchanges or by such system or by order of the Commission, FINRA or any other governmental authority, or

44

(iv) if a material disruption has occurred in commercial banking or securities settlement or clearance services in the United States, or (v) if a general moratorium on commercial banking has been declared by either federal or New York authorities, or (vi) if S&P and/or Moody’s downgrades or announces a potential downgrade or a review for possible ratings changes in any of the Company’s outstanding debt.

14. Information Furnished by the Underwriters. The Company and the Trust acknowledge that (i) the list of Underwriters and their respective participation in the sale of Units, (ii) the first and second sentences of the fourth paragraph, (iii) the twelfth through seventeeth paragraphs, the nineteenth paragraph and the twenty-second paragraph, each under the caption “Underwriting” in the most recent Preliminary Prospectus, constitute the only information furnished by or on behalf of the Underwriters through you or on your behalf as such information is referred to in Sections 6.1(d), 6.1(e), 6.1(f) and 6.1(g) and 8 hereof.

15. Miscellaneous. Notice given pursuant to any of the provisions of this Agreement shall be in writing and shall be delivered:

(i) to the Company

Whiting Petroleum Corporation

1700 Broadway, Suite 2300

Denver, Colorado 80290-2300

Attention: Chief Financial Officer

with a copy to

Foley & Lardner LLP

777 East Wisconsin Avenue

Milwaukee, Wisconsin 53202

Attention: Benjamin F. Garmer, III

(ii) to the Trust

The Bank of New York Trust Company, N.A.

Global Corporate Trust

221 West Sixth Street, 1st Floor

Austin, Texas 78701

Attention: Mike J. Ulrich

with a copy to

Bracewell & Giuliani LLP

111 Congress Avenue

Suite 2300

Austin, Texas 78701

Attention: Thomas Adkins

45

(iii) to the Underwriters

Raymond James & Associates, Inc.

880 Carillon Parkway

St. Petersburg, Florida 33716

Attention: John Critchlow

Morgan Stanley & Co. Incorporated

1585 Broadway

New York, New York 10036

Attention: Janet Livingston

Wachovia Capital Markets, LLC

375 Park Avenue

New York, New York 10152

Attention: Michael Golden

with a copy to

Vinson & Elkins L.L.P.

1001 Fannin Street, Suite 2300

Houston, Texas 77002

Attention: David P. Oelman

This Agreement has been and is made solely for the benefit of the several Underwriters, the Company and its directors and officers and the Trust.

16. No Fiduciary Duty. Notwithstanding any preexisting relationship, advisory or otherwise, between the parties or any oral representations or assurances previously or subsequently made by any of the Underwriters, each of the Company and the Trust acknowledges and agrees that (i) nothing herein shall create a fiduciary or agency relationship between the Company and the Trust, on the one hand, and the Underwriters, on the other hand; (ii) the Underwriters have been retained solely to act as underwriters and, except to the extent set out in clause (xi) of Section 7 hereof are not acting as advisors, expert or otherwise, to either the Company or the Trust in connection with this offering, the sale of the Units or any other services the Underwriters may be deemed to be providing hereunder, including, without limitation, with respect to the public offering price of the Units; (iii) the relationship between the Company and the Trust, on the one hand, and the Underwriters, on the other hand, is entirely and solely commercial, and the price of the Units was established by the Company and the Underwriters based on discussions and arms’ length negotiations and each of the Company and the Trust understands and accepts the terms, risks and conditions of the transactions contemplated by this Agreement; (iv) any duties and obligations that the Underwriters may have to the Company or the Trust shall be limited to those duties and obligations specifically stated herein; and (v) notwithstanding anything in this Agreement to the contrary, each of the Company and the Trust acknowledges that the Underwriters may have financial interests in the success of the Offering that are not limited to the difference between the price to the public and the purchase price paid to the Company by the Underwriters for the Units and that such interests may differ from the interests of the Company and the Trust, and the Underwriters have no obligation to disclose, or account to the Company or the Trust for any benefit that they may derive from, such additional

46

financial interests. Each of the Company and the Trust hereby waives and releases, to the fullest extent permitted by applicable law, any claims that the Company or the Trust may have against the Underwriters with respect to any breach or alleged breach of fiduciary duty and agree that the Underwriters shall have no liability (whether direct or indirect) to the Company or the Trust in respect of such a fiduciary duty claim or to any person asserting a fiduciary duty claim on behalf of or in right of the Company or the Trust or any of their respective members, managers, employees or creditors.

17. Applicable Law; Counterparts. This Agreement shall be governed by and construed in accordance with the laws of the State of New York without reference to choice of law principles thereunder.

This Agreement may be signed in various counterparts, which together shall constitute one and the same instrument.

This Agreement shall be effective when, but only when, at least one counterpart hereof shall have been executed on behalf of each party hereto.

The Company, the Trust and the Underwriters each hereby irrevocably waive any right they may have to a trial by jury in respect to any claim based upon or arising out of this Agreement or the transactions contemplated hereby.

18. Limitation of Trustee’s Liability. It is expressly understood and agreed by the parties hereto that (i) this Agreement is executed and delivered by the Trustee not individually or personally, but solely as Trustee on behalf of the Trust and (ii) under no circumstances shall the Trustee be liable for the breach or failure of any obligation, representation, warranty or covenant made or undertaken by the Trust under this Agreement.

19. Patriot Act Compliance. In accordance with the requirements of the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)), the Underwriters are required to obtain, verify and record information that identifies their respective clients, including the Company, which information may include the name and address of their respective clients, as well as other information that will allow the Underwriters to properly identify their respective clients.

47

Please confirm that the foregoing correctly sets forth the agreement among the Company, the Trust and the several Underwriters.

Very truly yours,
WHITING PETROLEUM CORPORATION
By:
	Name:
	Title:

WHITING USA TRUST II
By:	The Bank of New York Mellon Trust Company, N.A., as Trustee

By:
	Name:
	Title:

CONFIRMED as of the date first above mentioned, on behalf of the Representatives and the other several Underwriters named in Schedule I hereto.

RAYMOND JAMES & ASSOCIATES, INC.
By:
	Authorized Representative

MORGAN STANLEY & CO. LLC
By:
	Authorized Representative

SCHEDULE I

Name	Number Firm Units
Raymond James & Associates, Inc.		[l]
Morgan Stanley & Co. LLC		[l]
J.P. Morgan Securities LLC		[l]
Robert W. Baird & Co. Incorporated		[l]
Oppenheimer & Co. Inc.		[l]
RBC Capital Markets, LLC		[l]
Stifel, Nicolaus & Company, Incorporated		[l]
Morgan Keegan & Co., Inc.		[l]
Wunderlich Securities, Inc.		[l]
Total:		16,000,000

I-1

SCHEDULE II

Free Writing Prospectuses

Issuer Free Writing Prospectuses included in the Time of Sale Information: None.

Issuer Free Writing Prospectus not included in the Time of Sale Information: Electronic roadshow as made available on http://www.netroadshow.com.

II-1

SCHEDULE III

Information Included in “Time of Sale Information”

Trust units offered:	16,000,000
Public offering price:	$[l] per Trust Unit

III-1

SCHEDULE IV

LIST OF STATES

Arkansas

Colorado

Michigan

Mississippi

Montana

New Mexico

North Dakota

Oklahoma

Texas

Wyoming

IV-1

SCHEDULE V

Colorado and Wyoming	Holland & Hart LLP
Mississippi	Butler, Snow, O’Mara, Stevens & Canada PLLC
New Mexico	Modrall, Sperling, Roehl, Harris & Sisk, P.A.
North Dakota	Crowley Fleck, PLLP
Texas	Cotton Bledsoe Tighe & Dawson, P.C.

V-1

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the use in this Amendment No. 2 to Registration Statement No. 333-178586 on Form S-1 of (i) our report dated March 2, 2012 relating to the statements of historical revenues and direct operating expenses of the Underlying Properties (which report expresses an unqualified opinion and includes an explanatory paragraph related to the correction of a misstatement) and (ii) our report dated December 16, 2011 relating to the statement of assets and trust corpus of Whiting USA Trust II, appearing in the Prospectus, which is part of this Registration Statement. We also consent to the reference to us under the heading “Experts” in such Prospectus.

/s/ Deloitte & Touche LLP

Denver, Colorado

March 2, 2012

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in this Amendment No. 2 to Registration Statement No. 333-178586 on Form S-3 of our reports dated February 23, 2012 relating to the financial statements and financial statement schedule of Whiting Petroleum Corporation (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the Company’s adoption of new accounting guidance), and the effectiveness of Whiting Petroleum Corporation’s internal control over financial reporting, appearing in the Annual Report on Form 10-K of Whiting Petroleum Corporation for the year ended December 31, 2011, and to the reference to us under the heading “Experts” in the Prospectus, which is part of this Registration Statement.

/s/ Deloitte & Touche LLP

Denver, Colorado

March 2, 2012

EX-23.3

Exhibit 23.3

CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS

9601 AMBERGLEN BLVD., SUITE 117	306 WEST SEVENTH STREET, SUITE 302	1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1106	FORT WORTH, TEXAS 76102-4987	HOUSTON, TEXAS 77002-5008
512-249-7000	817- 336-2461	713-651-9944
	www.cgaus.com

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the references to our firm in the form and context in which they are included in this amendment to the registration statement on Form S-1 and Form S-3 filed by Whiting USA Trust II and Whiting Petroleum Corporation, respectively (collectively, the “Registration Statement”), including the related prospectus that is a part thereof, to our estimates of reserves and value of reserves and our report on reserves as of December 31, 2011 of the underlying properties and net profits interest owned by Whiting USA Trust II and to the inclusion of our report dated December 9, 2011 as an appendix to the prospectus included in the Registration Statement.

We also consent to the references to our firm in the form and context in which they are incorporated by reference in the Registration Statement and the related prospectus that is a part thereof. We hereby further consent to the incorporation by reference of information contained in our report setting forth the estimates of revenues from Whiting Petroleum Corporation’s oil and gas reserves as of December 31, 2011.

We also consent to the references to our firm in the prospectus included in such registration statement, including under the heading “Experts.”

Sincerely,

Cawley, Gillespie & Associates, Inc.

Texas Registered Engineering Firm F-693

March 2, 2012

Fort Worth, Texas

CORRESP

March 2, 2012 ATTORNEYS AT LAW   777 EAST WISCONSIN AVENUE MILWAUKEE, WI 53202 414.271.2400 TEL 414.297.4900 FAX foley.com   WRITER’S DIRECT LINE 414.319.7348 brikkers@foley.com EMAIL   CLIENT/MATTER NUMBER 038584-0127

CORRESP

MEMORANDUM

TO:	Division of Corporation Finance Securities and Exchange Commission
FROM:	Whiting Petroleum Corporation Whiting USA Trust II
DATE:	March 2, 2012
RE:	Whiting USA Trust II	Whiting Petroleum Corporation
	Amendment No. 1 to Registration	Amendment No. 1 to Registration
	Statement on Form S-1	Statement on Form S-3
	Filed on January 30, 2012	Filed on January 30, 2012
	File No. 333-178586	File No. 333-178586-01

This memorandum sets forth the responses of Whiting Petroleum Corporation (“Whiting”) and Whiting USA Trust II (the “Trust” and, collectively with Whiting, the “Registrants”) to the comments contained in the letter, dated February 21, 2012, of the staff of the Division of Corporation Finance of the Securities and Exchange Commission (the “Staff”) with respect to Amendment No. 1 to the above-referenced Registration Statement (the “Registration Statement”). For the convenience of the Staff, each of the Staff’s comments is repeated below in italics, and set forth below each such comment is the Registrants’ response.

Amendment No. 1 to Registration Statement on Form S-1 and Form S-3

Prospectus Summary

1. We note your response to comment 6 from our letter dated January 20, 2012. Please revise your filing to include the information presented in your response.

The Registrants acknowledge the Staff’s comment and have included the additional disclosures on pages 2 to 3 and 52 of the prospectus.

Projected Cash Distributions, page 36

2. We note your response to comment 11 from our letter dated January 20, 2012. Please expand the table on page 38 to disclose the oil and gas sales volumes and sales price for each of the prior periods, comparable to the information provided in the projected cash distributions table on page 41.

The Registrants acknowledge the Staff’s comment and have included the additional disclosure on page 39 of the prospectus.

Sensitivity of Projected Cash Distributions to Oil, Natural Gas and Natural Gas Liquids Production and Prices, page 42

3. We note your response to comment 13 from our letter dated January 20, 2012. Please revise your filing to include the information presented in your response.

The Registrants acknowledge the Staff’s comment and have included the additional disclosure on page 47 of the prospectus.

*    *    *

The Registrants also note that the Registration Statement has been updated to include the following items as referenced in the Registrants’ responses to previous Staff comments:

• All blanks have been filled in other than the information that Rule 430A permits the Registrants to omit.

• Information relating to: (i) full-year 2011 financial information, (ii) information regarding the hedges Whiting has entered into relating to the underlying properties, (iii) updated 2012 projected cash distribution amounts based on recent NYMEX prices and (iv) revised cash distribution sensitivity tables based on the revised information in items (ii) and (iii).

• Expanding the year-end 2011 proved reserves table for the underlying properties to disclose reserve movements during 2011 as well as proved developed and proved undeveloped reserve volumes.

Further, in response to the Staff’s request to provide all promotional and sales material prior to their use, the Registrants note that they are, under separate cover, submitting supplementally a draft of their road show presentation.

2