Table of Contents

As filed with the Securities and Exchange Commission on January 30, 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. 1 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. 1 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)

 

 

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.

 

 

 

---

Table of Contents

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 January 30, 2012

PRELIMINARY PROSPECTUS

Whiting USA Trust II

15,870,000 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 18,250,500 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 $             and $            . The trust intends to apply to have the trust units approved for listing on the New York Stock Exchange under the symbol “WHZ.”

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.

 

•

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 2,380,500 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

 

The date of this prospectus is                     , 2012

---

Table of Contents

 

 

---

Table of Contents

TABLE OF CONTENTS

 

		Page
PROSPECTUS SUMMARY			1
RISK FACTORS			18
FORWARD-LOOKING STATEMENTS			32
USE OF PROCEEDS			33
WHITING PETROLEUM CORPORATION			34
THE TRUST			36
PROJECTED CASH DISTRIBUTIONS			37
THE UNDERLYING PROPERTIES			47
COMPUTATION OF NET PROCEEDS			72
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 72) 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 47;

---

Table of Contents

•

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 72; 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.

---

Table of Contents

 

1

---

Table of Contents

 

2

---

Table of Contents

 

3

---

Table of Contents

 

4

---

Table of Contents

 

5

---

Table of Contents

 

6

---

Table of Contents

 

7

---

Table of Contents

 

8

---

Table of Contents

 

9

---

Table of Contents

 

10

---

Table of Contents

 

11

---

Table of Contents

 

12

---

Table of Contents

 

13

---

Table of Contents

 

14

---

Table of Contents

 

15

---

Table of Contents

 

16

---

Table of Contents

 

17

---

Table of Contents

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                      , 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 threats by Iran to block the Strait of Hormuz;

 

•

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.

 

18

---

Table of Contents

Recent oil prices have been high compared to historical prices. For example, the NYMEX crude oil spot prices per Bbl were $44.60 and $79.36 as of December 31, 2008 and 2009, 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
Crude Oil (per Bbl)		$	78.79			$	77.99			$	76.21			$	85.18			$	94.25			$	102.55			$	89.81
Natural Gas (per MMBtu)		$	5.30			$	4.09			$	4.39			$	3.81			$	4.10			$	4.32			$	4.20

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                     , 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 $89.74 per Bbl in the case of crude oil and $5.03 per Mcf in the case of natural gas. However, actual sales prices 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,

 

19

---

Table of Contents

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.

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 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.

 

20

---

Table of Contents

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 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

 

21

---

Table of Contents

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 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 9.3% from the nine months ended September 30, 2010 to the nine months ended September 30, 2011. 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

 

22

---

Table of Contents

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.”

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.

 

23

---

Table of Contents

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.

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.

 

24

---

Table of Contents

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, acting as representative of the several underwriters. See “Underwriting.” In connection with the closing of this offering, Whiting and the trust intend to enter into a registration rights agreement pursuant to which the trust will agree to file a registration statement or shelf registration statement to register the resale of the remaining trust units held by Whiting and any transferee of the trust units upon request by such holders. See “Trust units eligible for future sale — Registration rights.”

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

The number of trust units to be delivered to Whiting in exchange for the net profits interest and the initial public offering price of the trust units will be determined by negotiation among Whiting and the underwriters. Among the factors to be considered in determining such number of trust units and the initial public offering price, in addition to prevailing market conditions, will be current and historical oil and natural gas prices, current and prospective conditions in the supply and demand for oil and natural gas, reserve and production quantities estimated for the net profits interest and the trust’s estimated cash distributions. None of Whiting, the trust or the underwriters will obtain any independent appraisal or other opinion of the value of the net profits interest other than the reserve report prepared by Cawley, Gillespie & Associates, Inc.

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

The trading price for publicly traded securities similar to the trust units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the trust will vary in response to numerous factors outside the control of the trust, including prevailing 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 investors as a return of capital, with the remainder being considered as a return on investment. As a result, distributions made to a unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the unitholder.

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

The interests of Whiting and the interests of the trust and the trust unitholders with respect to the underlying properties could at times differ. For example:

 

•

Whiting’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

 

25

---

Table of Contents

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.

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

 

26

---

Table of Contents

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.

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

 

27

---

Table of Contents

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 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

 

28

---

Table of Contents

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.

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 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.

 

29

---

Table of Contents

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.”

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.

 

30

---

Table of Contents

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.”

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.

 

31

---

Table of Contents

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.

 

32

---

Table of Contents

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 18,250,500 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 $         million, assuming the underwriters do not exercise their over-allotment option, associated with this offering and will receive all net proceeds from the offering. The estimated net proceeds to Whiting will be approximately $         million, and will increase to approximately $         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 September 30, 2011 and mature in April 2016.

 

33

---

Table of Contents

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, 2010, Whiting had total estimated net proved reserves of 304.9 MMBOE and during the three months ended September 30, 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 September 30, 2011, on a cumulative accrual basis, 4.72 MMBOE of the total 8.20 MMBOE have been produced and sold and a cumulative 0.02 MMBOE have been divested. Per the 2008 trust’s Quarterly Report on Form 10-Q filed with the SEC on November 8, 2011, the 9.11 MMBOE of reserves are projected to be produced by November 30, 2015, based on the 2008 trust’s reserve report for the underlying properties as of December 31, 2010. The production of 9.11 MMBOE by November 30, 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.

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

 

34

---

Table of Contents

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.

 

35

---

Table of Contents

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 18,250,500 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.

 

36

---

Table of Contents

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 SEPTEMBER 30, 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 October 1, 2010. 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 October 1, 2010 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.

 

37

---

Table of Contents

Unaudited Pro Forma Cash Distributions on Trust Units

 

		Quarter Ended
		December 31, 2010				March 31, 2011				June 30, 2011				September 30, 2011
		(dollars in thousands, except per trust unit amounts)
Calculation of net proceeds:
Gross proceeds:
Oil and natural gas liquids sales		$	24,336			$	26,220			$	30,083			$	32,877
Natural gas sales			4,313				4,083				4,581				4,230
Total		$	28,649			$	30,303			$	34,664			$	37,107
Production and development costs:
Lease operating costs		$	8,154			$	8,919			$	8,291			$	8,849
Production taxes			1,566				1,715				1,895				2,037
Development costs			10,757				5,388				2,896				5,463
Total		$	20,477			$	16,022			$	13,082			$	16,349
Net proceeds		$	8,172			$	14,281			$	21,582			$	20,758
Percentage allocable to net profits interest			90	%			90	%			90	%			90	%
Total cash proceeds to trust		$	7,354			$	12,852			$	19,424			$	18,683
Trust administrative expenses(1)			94				94				94				94
Cash distributable on trust units before state income tax withholdings		$	7,260			$	12,758			$	19,330			$	18,589
State income tax withholdings			20				27				17				30
Cash distributions on trust units		$	7,240			$	12,731			$	19,313			$	18,559
Cash distributions per trust unit before state income tax withholdings		$	0.40			$	0.70			$	1.06			$	1.01
Cash distributions per trust unit		$	0.40			$	0.70			$	1.06			$	1.01

 

(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 $7.1 million (or $0.39 per unit), $12.6 million (or $0.69 per unit), $19.2 million (or $1.05 per unit) and $18.4 million (or $1.01 per unit) for the quarters ended December 31, 2010, March 31, 2011, June 30, 2011 and September 30, 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 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.

 

38

---

Table of Contents

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          months ending December 31, 2012.

The projected financial information was based on the hypothetical assumption that prices for oil and natural gas for each month during the twelve-month period from January 1, 2012 to December 31, 2012 equal the NYMEX futures prices for oil and natural gas on December 9, 2011 for such month, as set forth in the table below. To estimate the price for natural gas liquids, Whiting used a hypothetical price equal to approximately 68% of the assumed NYMEX price used in the table below for oil, which is consistent with the historical pricing realized by Whiting for natural gas liquids.

 

		Hypothetical Prices for Oil and Natural Gas for 2012(1)
		Jan.				Feb.				March				April				May				June				July				Aug.				Sept.				Oct.				Nov.				Dec.
Oil (per Bbl)		$	99.41			$	99.60			$	99.75			$	99.89			$	99.93			$	99.80			$	99.57			$	99.30			$	99.04			$	98.80			$	98.61			$	98.39
Natural Gas (per MMBtu)		$	3.32			$	3.35			$	3.37			$	3.41			$	3.46			$	3.50			$	3.55			$	3.57			$	3.58			$	3.61			$	3.75			$	4.03

 

(1)	The estimated prices for oil and natural gas are based such month’s NYMEX futures prices for oil and natural gas on December 9, 2011.

The assumed 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. For more information about differential assumptions, please see “—Significant assumptions used to prepare the cash distributions — Oil, natural gas and natural gas liquids prices.” 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 monthly closing NYMEX crude oil spot price per Bbl was $96.85 from January 1, 2011 through September 30, 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

 

39

---

Table of Contents

contracts. The hedge contracts will limit the potential for increases in cash distributions due to oil price increases from                     , 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                     , 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.”

 

40

---

Table of Contents

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 NYMEX price:
Oil (per Bbl)		$	99.60			$	99.87			$	99.30			$	98.60			$	99.35
Natural gas (per MMBtu)		$	3.36			$	3.45			$	3.57			$	3.79			$	3.56
Assumed realized sales price:
Oil (per Bbl)		$	90.32			$	90.09			$	89.74			$	88.83			$	89.74
Natural gas (per Mcf)		$	4.79			$	4.90			$	5.09			$	5.26			$	5.03
Calculation of net proceeds:
Gross proceeds:
Oil and natural gas liquids sales		$	27,457			$	29,099			$	28,626			$	27,803			$	112,985
Natural gas sales			1,886				3,109				3,101				3,108				11,204
Total		$	29,343			$	32,208			$	31,727			$	30,911			$	124,189
Production and development costs:
Lease operating expenses		$	8,367			$	8,344			$	8,330			$	8,309			$	33,350
Production taxes			1,518				1,773				1,751				1,701				6,743
Development costs			1,280				702				3,275				1,049				6,306
Payments made (or received) by Whiting to settle hedge contracts(2)			—				—				—				—				—
Total		$	11,165			$	10,819			$	13,356			$	11,059			$	46,399
Whiting expense reserve(3)			—				—				—				—				—
Net proceeds		$	18,178			$	21,389			$	18,371			$	19,852			$	77,790
Percentage allocable to net profits interest			90	%			90	%			90	%			90	%			90	%
Total cash proceeds to trust		$	16,360			$	19,250			$	16,534			$	17,867			$	70,011
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		$	16,110			$	19,000			$	16,284			$	17,617			$	69,011
Trustee reserve for future trust expenses(5)			—				—				—				—				—
State income tax withholdings(6)			20				19				18				16				73
Projected cash distributions on trust units		$	16,090			$	18,981			$	16,266			$	17,601			$	68,938
Projected cash distributions per trust unit before state income tax withholdings and reserve for future trust expenses		$	0.88			$	1.04			$	0.89			$	0.97			$	3.78
Projected cash distributions per trust unit		$	0.88			$	1.04			$	0.89			$	0.96			$	3.78

 

(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.

 

41

---

Table of Contents

(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

 

42

---

Table of Contents

underlying properties after 2014. Differing levels of production will result in different levels of distributions and cash returns.

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.    Hypothetical oil and natural gas prices assumed in the projected cash distributions table are based on NYMEX futures prices for oil and natural gas on December 9, 2011 and adjusted as described in more detail above in “— Projected cash distributions.” Published NYMEX benchmark prices for crude oil are based upon an assumed light, sweet crude oil of a particular gravity that is stored in Cushing, Oklahoma while published NYMEX benchmark prices for natural gas are based upon delivery at the Henry Hub in Louisiana. These prices differ from the average or actual price received for production attributable to the underlying properties. Differentials between published oil and natural gas prices and the prices actually received for the oil and natural gas production may vary significantly due to market conditions, transportation costs and other factors.

For 2012, $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 NYMEX 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, $1.47 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 published 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 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.

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 a weighted average floor of $         and weighted average ceiling of $         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 to be $33.4 million and production taxes to be $6.7 million. For the nine months ended September 30, 2011, lease operating expenses were $27.3 million and production taxes were $5.7 million. 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

 

43

---

Table of Contents

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 18,250,500 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 commodity prices based upon NYMEX futures prices for oil and natural gas on December 9, 2011; (4) the impact of the hedge contracts entered into by Whiting that relate to production from the underlying properties; and (5) other assumptions described below under “— Significant assumptions used to prepare the projected cash distributions.” The hypothetical commodity prices of oil, natural gas and natural gas liquids production shown have been chosen solely for illustrative purposes.

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 NYMEX futures 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                     , 2012 through December 31, 2014. These hedge contracts are costless collar arrangements that hedge approximately 50% of the anticipated oil production attributable to the underlying properties. The crude oil hedge contracts are priced with floors ranging from $         to $         and ceilings ranging from $         to $         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. The sensitivity information presented below does not give effect to the hedge contracts that Whiting has entered into with respect to the oil production from the underlying properties.

 

44

---

Table of Contents

Sensitivity of 2012 Projected Cash Distributions Per Trust Unit

to Changes in Estimated Oil and Natural Gas Production and NYMEX Futures Pricing

 

						Quarter Ending March 31, 2012 Projected Distributions Per Unit         % of Estimated NYMEX Futures Pricing(2)
						70%				80%				90%				100%				110%				120%				130%
			85	%		$	0.37			$	0.49			$	0.61			$	0.74			$	0.86			$	0.98			$	1.11
			90	%			0.40				0.53				0.66				0.79				0.92				1.05				1.18
			95	%			0.42				0.56				0.70				0.83				0.97				1.11				1.25
			100	%			0.45				0.59				0.74				0.88				1.03				1.17				1.32
			105	%			0.47				0.63				0.78				0.93				1.08				1.23				1.39
			110	%			0.50				0.66				0.82				0.98				1.14				1.30				1.46
			115	%			0.53				0.69				0.86				1.03				1.19				1.36				1.52

 

						Quarter Ending June 30, 2012 Projected Distributions Per Unit     % of Estimated NYMEX Futures Pricing(3)
						70%				80%				90%				100%				110%				120%				130%
			85	%		$	0.47			$	0.61			$	0.74			$	0.88			$	1.01			$	1.15			$	1.28
			90	%			0.50				0.65				0.79				0.93				1.07				1.22				1.36
			95	%			0.53				0.68				0.84				0.99				1.14				1.29				1.44
			100	%			0.57				0.72				0.88				1.04				1.20				1.36				1.51
			105	%			0.60				0.76				0.93				1.09				1.26				1.43				1.59
			110	%			0.63				0.80				0.97				1.15				1.32				1.50				1.67
			115	%			0.66				0.84				1.02				1.20				1.39				1.57				1.75

 

						Quarter Ending September 30, 2012 Projected Distributions Per Unit     % of Estimated NYMEX Futures Pricing(4)
						70%				80%				90%				100%				110%				120%				130%
			85	%		$	0.33			$	0.47			$	0.60			$	0.73			$	0.86			$	1.00			$	1.13
			90	%			0.36				0.50				0.64				0.78				0.92				1.07				1.21
			95	%			0.39				0.54				0.69				0.84				0.99				1.13				1.28
			100	%			0.42				0.58				0.74				0.89				1.05				1.20				1.36
			105	%			0.45				0.62				0.78				0.94				1.11				1.27				1.44
			110	%			0.48				0.66				0.83				1.00				1.17				1.34				1.51
			115	%			0.51				0.69				0.87				1.05				1.23				1.41				1.59

 

						Quarter Ending December 31, 2012 Projected Distributions Per Unit     % of Estimated NYMEX Futures Pricing(5)
						70%				80%				90%				100%				110%				120%				130%
			85	%		$	0.42			$	0.55			$	0.68			$	0.81			$	0.94			$	1.07			$	1.20
			90	%			0.45				0.59				0.72				0.86				1.00				1.13				1.27
			95	%			0.48				0.62				0.77				0.91				1.06				1.20				1.35
			100	%			0.51				0.66				0.81				0.96				1.12				1.27				1.42
			105	%			0.54				0.70				0.86				1.02				1.18				1.34				1.49
			110	%			0.57				0.73				0.90				1.07				1.23				1.40				1.57
			115	%			0.59				0.77				0.94				1.12				1.29				1.47				1.64

 

45

---

Table of Contents

						Year Ending December 31, 2012 Projected Distributions Per Unit     % of Estimated NYMEX Futures Pricing(6)
						70%				80%				90%				100%				110%				120%				130%
			85	%		$	1.60			$	2.12			$	2.64			$	3.16			$	3.67			$	4.19			$	4.71
			90	%			1.71				2.26				2.81				3.36				3.91				4.46				5.01
			95	%			1.83				2.41				2.99				3.57				4.15				4.73				5.31
			100	%			1.95				2.56				3.17				3.78				4.39				5.00				5.61
			105	%			2.06				2.70				3.34				3.98				4.63				5.27				5.91
			110	%			2.18				2.85				3.52				4.19				4.86				5.54				6.21
			115	%			2.29				2.99				3.70				4.40				5.10				5.80				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 NYMEX price of $99.60 per Bbl in the case of oil and $3.36 per MMBtu in the case of natural gas.

(3)	Based on an assumed NYMEX price of $99.87 per Bbl in the case of oil and $3.45 per MMBtu in the case of natural gas.

(4)	Based on an assumed NYMEX price of $99.30 per Bbl in the case of oil and $3.57 per MMBtu in the case of natural gas.

(5)	Based on an assumed NYMEX price of $98.60 per Bbl in the case of oil and $3.79 per MMBtu in the case of natural gas.

(6)	Based on an assumed NYMEX price of $99.35 per Bbl in the case of oil and $3.56 per MMBtu in the case of natural gas.

 

46

---

Table of Contents

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 September 30, 2011, the average daily net production from the underlying properties was approximately 5,007 BOE/d (or 4,507 BOE/d attributable to the net profits interest) and was comprised of approximately 73% oil, 24% 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

 

47

---

Table of Contents

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, 2010, and for the nine-month periods ended September 30, 2010 and 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,												Nine Months Ended September 30,
		2008				2009				2010				2010				2011
		(dollars in thousands)
Revenues:
Oil sales(1)		$	159,243			$	85,826			$	104,667			$	77,013			$	90,711
Natural gas sales			34,924				19,791				19,041				14,499				12,537
Total revenues		$	194,167			$	105,617			$	123,708			$	91,512			$	103,248
Direct operating expenses:
Lease operating		$	35,106			$	31,935			$	33,876			$	24,641			$	27,287
Production taxes			10,992				5,718				6,571				5,117				5,675
Total direct operating expenses		$	46,098			$	37,653			$	40,447			$	29,758			$	32,962
Excess of revenues over direct operating expenses		$	148,069			$	67,964			$	83,261			$	61,754			$	70,286

 

(1)	Includes natural gas liquids.

 

48

---

Table of Contents

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, 2010, and for the nine-month periods ended September 30, 2010 and 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,												Nine Months Ended September 30,
		2008				2009				2010				2010				2011
Net sales volumes:
Oil (MBbl)(1)			1,755				1,572				1,459				1,096				1,040
Natural gas (MMcf)			3,825				4,318				3,335				2,522				2,008
Total sales volumes (MBOE)			2,393				2,292				2,015				1,516				1,375
Average realized sales prices:
Oil (per Bbl)(1)		$	90.74			$	54.60			$	71.74			$	70.27			$	87.22
Natural gas (per Mcf)		$	9.13			$	4.58			$	5.71			$	5.75			$	6.24
Capital expenditures (in thousands)		$	52,971			$	20,229			$	25,969			$	22,125			$	14,455

 

(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. These statements give 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, 2010. 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 are for information purposes only. They do not purport to present the results that would have actually occurred had the net profits interest conveyance been completed on the assumed dates or for the periods presented or which may be realized in the future.

 

		Year Ended December 31, 2010				Nine Months Ended September 30, 2011
		(dollars in thousands, except per unit amounts)
Historical results
Income from Net Profits Interest		$	50,177			$	50,959
Pro Forma Adjustments
Less:
Trust general and administrative expenses			(375	)			(281	)
State income tax withholdings			(77	)			(74	)
Distributable income		$	49,725			$	50,604
Distributable income per unit		$	2.72			$	2.77

 

49

---

Table of Contents

DISCUSSION AND ANALYSIS OF HISTORICAL RESULTS OF THE UNDERLYING PROPERTIES

Comparison of results of the underlying properties for the nine months ended September 30, 2011 and 2010

Revenues.    Oil and natural gas sales revenue increased $11.7 million in the first nine months of 2011 compared to the first nine months of 2010. Sales are a function of average sales prices and volumes sold. The average prices realized for oil and natural gas increased 24% and 9%, respectively, between periods. Oil sales volumes decreased 5% or 56 MBbl between periods primarily due to normal field production decline. Natural gas sales volumes decreased 20% or 514 MMcf between periods. The primarily cause of this decrease in natural gas volumes was normal field production decline of 278 MMcf from 2010 to 2011. In addition, there were six wells that experienced higher than average production decline rates in 2010 and 2011. Production from these six wells decreased 276 MMcf in the first nine months of 2011 compared to the first nine months of 2010. These six wells were drilled in the latter portion of 2008 and were therefore in their initial steep decline phases 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. Lastly, there were four wells that were either shut-in for a portion of 2011 or that had gas gathering systems go down, which contributed an additional 60 MMcf of natural gas production decreases in 2011. These natural gas production decreases were partially offset by an increase of 100 MMcf between periods due to eight new wells drilled in the latter half of 2010 and early 2011.

Lease operating expenses.    Lease operating expenses increased $2.6 million in the first nine months of 2011 compared to the first nine months of 2010, and lease operating expenses per BOE increased from $16.25 during the first nine months of 2010 to $19.85 during the first nine months of 2011. The increase of 22% on a BOE basis was primarily caused by a high level of workover activity in the first nine months of 2011 and a decrease in production volumes between periods. Workovers amounted to $6.5 million in the first nine months of 2011, as compared to $4.0 million in the same period in 2010, and overall oil and natural gas production volumes decreased by 142 MBOE between periods. Whiting cannot provide any assurance that workovers will continue to occur at this level.

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 the first nine months of 2011 and 2010 were consistent between periods at 6% of oil and natural gas sales.

Excess of revenues over direct operating expenses.    Excess of revenues over direct operating expenses increased $8.5 million from the first nine months of 2010 to the first nine months of 2011. The reasons for this increase included a 24% 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 the first nine months of 2011.

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

 

50

---

Table of Contents

incremental natural gas production of 109 MMcf in 2010. 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 $1.9 million from 2009 to 2010, and lease operating expenses per BOE increased from $13.94 during 2009 to $16.81 during 2010. The increase of 21% on a BOE basis was primarily caused by a high level of workover activity in 2010 and a decrease in production volumes between periods. Workovers amounted to $6.0 million in 2010, as compared to $3.4 million in 2009, and overall oil and natural gas production volumes decreased by 277 MBOE between periods. Whiting cannot provide any assurance that workovers will continue to occur at this level.

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 $15.3 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.

Comparison of results of the underlying properties for the year ended December 31, 2009 compared to year ended December 31, 2008

Revenues.    Oil and natural gas sales revenue decreased $88.6 million to $105.6 million from 2008 to 2009. Sales are a function of average sales prices and volumes sold. The average prices realized for oil and natural gas decreased 40% and 50%, respectively, between periods. Likewise, oil sales volumes decreased 10% or 183 MBbl between periods mainly due to normal field production decline. Natural gas sales volumes increased 13% or 493 MMcf between periods primarily due to new wells drilled in the latter half of 2008 and early 2009. Six wells drilled in latter 2008 and early 2009 added 1,147 MMcf of natural gas production in 2009 as compared to 2008. These natural gas production increases were partially offset by production volume decreases totaling 654 MMcf from 2008 to 2009. Normal field production decline negatively impacted natural gas production by 392 MMcf between periods. Seven recently drilled wells had higher than average decline rates totaling 151 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. Lastly, seven wells that were shut-in for a portion of 2009 contributed an additional 111 MMcf of natural gas production decreases in 2009.

Lease operating expenses.    Lease operating expenses decreased $3.2 million from 2008 to 2009, and lease operating expenses per BOE decreased from $14.67 in 2008 to $13.94 in 2009. These decreases in LOE were primarily attributable to the cost of oil field goods and services being $3.0 million lower between periods, in connection with the reduced demand for industry goods and services in 2009.

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 2008 and 2009 were 6% and 5%, respectively, of oil and natural gas sales.

Excess of revenues over direct operating expenses.    Excess of revenues over direct operating expenses decreased $80.1 million from 2008 to 2009. The reasons for this decrease included a 40% decrease in oil prices and a 50% decrease in natural gas prices between periods, as well as a 4% decrease in equivalent volumes sold. These negative factors were partially offset by lower lease operating expenses and production taxes in 2009.

 

51

---

Table of Contents

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                     , 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. 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.

 

52

---

Table of Contents

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                     , 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
March 2012				$				$
April 2012				$				$
May 2012				$				$
June 2012				$				$
July 2012				$				$
August 2012				$				$
September 2012				$				$
October 2012				$				$
November 2012				$				$
December 2012				$				$
January 2013				$				$
February 2013				$				$
March 2013				$				$
April 2013				$				$
May 2013				$				$
June 2013				$				$
July 2013				$				$
August 2013				$				$
September 2013				$				$
October 2013				$				$
November 2013				$				$
December 2013				$				$
January 2014				$				$
February 2014				$				$
March 2014				$				$
April 2014				$				$
May 2014				$				$
June 2014				$				$
July 2014				$				$
August 2014				$				$
September 2014				$				$
October 2014				$				$
November 2014				$				$
December 2014				$				$

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

 

53

---

Table of Contents

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 September 30, 2011.

 

		Developed Acreage								Undeveloped Acreage								Total Acreage
		Gross				Net				Gross				Net				Gross				Net
Rocky Mountains			40,422				18,789				—				—				40,422				18,789
Permian Basin			31,933				23,505				680				244				32,613				23,749
Gulf Coast			11,186				4,469				470				164				11,656				4,633
Mid-Continent			3,683				2,198				—				—				3,683				2,198
Total			87,224				48,961				1,150				408				88,374				49,369

The following is a summary of the producing wells on the underlying properties as of September 30, 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,
		2008								2009								2010
		Gross				Net				Gross				Net				Gross				Net
Productive
Oil wells			16				8.82				12				4.37				10				8.07
Natural gas wells			3				1.07				2				0.04				—				—
Dry			1				1.00				—				—				—				—
Total			20				10.89				14				4.41				10				8.07

 

54

---

Table of Contents

During the nine months ended September 30, 2011, Whiting drilled, completed and commenced production with respect to 21 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,
		2008				2009				2010
Net sales volumes:
Oil production (MBbl)(1)			1,755				1,572				1,459
Natural gas production (MMcf)			3,825				4,318				3,335
Total production (MBOE)			2,393				2,292				2,015
Average daily production (MBOE/d)			6.5				6.3				5.5
Keystone, South field sales volumes(2):
Oil production (MBbl)(1)			179				178				154
Natural gas production (MMcf)			790				843				758
Total production (MBOE)			310				318				281
Rangely field sales volumes(2):
Oil production (MBbl)(1)			227				208				195
Natural gas production (MMcf)			-				-				-
Total production (MBOE)			227				208				195
Average sales prices:
Oil (per Bbl)(1)		$	90.74			$	54.60			$	71.74
Natural gas (per Mcf)		$	9.13			$	4.58			$	5.71
Production costs (per BOE)(3)		$	14.63			$	13.67			$	16.50

 

(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, 2008, 2009 and 2010.

(3)	Production costs reported above exclude from lease operating expenses ad valorem taxes of $0.1 million ($0.05/BOE), $0.6 million ($0.26/BOE) and $0.6 million ($0.31/BOE) for the years ended December 31, 2008, 2009 and 2010, 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.

 

55

---

Table of Contents

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 September 30, 2011.

 

						Estimated Proved Reserves As of December 31, 2011																												Three Months Ended September 30, 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	%			465
Garland			WY				1,145				370				1,207				94.9	%			11.4	%			41.2				12.7	%			478
Cedar Hills			ND				399				14				401				99.4	%			3.8	%			18.5				5.7	%			253
Torchlight			WY				635				—				635				100.0	%			6.0	%			16.5				5.1	%			218
Other							769				331				825				93.3	%			7.8	%			33.3				10.3	%			339
Rocky Mountains Total							4,353				715				4,473				97.3	%			42.2	%		$	146.2				45.2	%			1,753
Permian Basin (17 Fields)
Keystone, South			TX				846				4,052				1,521				55.6	%			14.3	%		$	42.7				13.2	%			576
Martin			TX				242				1,331				463				52.1	%			4.4	%			12.3				3.8	%			186
DEB			TX				440				68				452				97.5	%			4.3	%			15.6				4.8	%			255
Signal Peak			TX				158				3,002				659				24.0	%			6.2	%			13.4				4.2	%			341
Sable			TX				373				—				373				100.0	%			3.5	%			11.3				3.5	%			134
Other							810				1,572				1,072				75.6	%			10.1	%			32.8				10.1	%			444
Permian Basin Total							2,869				10,025				4,540				63.2	%			42.8	%		$	128.1				39.6	%			1,936
Gulf Coast (8 Fields)
Lake Como			MS				425				401				492				86.4	%			4.6	%		$	19.4				6.0	%			212
Other							275				2,496				690				39.8	%			6.5	%			16.2				5.0	%			436
Gulf Coast Total							700				2,897				1,182				59.2	%			11.1	%		$	35.6				11.0	%			648
Mid-Continent (10 Fields)
Wesson			AR				287				8				288				99.6	%			2.7	%		$	10.9				3.3	%			97
Other							69				337				125				55.0	%			1.2	%			2.8				0.9	%			73
Mid-Continent Total							356				345				413				86.1	%			3.9	%		$	13.7				4.2	%			170
Total (49 fields)							8,278				13,982				10,608				78.0	%			100.0	%		$	323.6				100.0	%			4,507

 

(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.

 

56

---

Table of Contents

(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 September 30, 2011 attributable to the net profits interest of 4,507 BOE/d, approximately 76% was oil and natural gas liquids and 24% 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 1,753 BOE/d for the three months ended September 30, 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

5,847/3,550

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

%

 

57

---

Table of Contents

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 84% of these properties based on average daily net production attributable to the net profits interest of 1,936 BOE/d for the three months ended September 30, 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

7,411/7,411

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

14,493/8,804

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 648 BOE/d for the three months ended September 30, 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

1,054/770

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 88% of these properties based on average daily net production attributable to the net profits interest of 170 BOE/d for the three months ended September 30, 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

 

58

---

Table of Contents

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 $4.2 million per year over the three year period ending December 31, 2010. 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 working interest owners meeting held on November 2, 2011, the 2012 capital expenditure budget is $68.4 million

 

59

---

Table of Contents

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. 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 $24.3 million per year over the three year period ending December 31, 2010. 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 $4.5 million per year over the three year period ending December 31, 2010. 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.

 

60

---

Table of Contents

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, 2010. 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

---

Table of Contents

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 external quarterly reviews, annual audits and their own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using the criteria set forth in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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 the aforementioned internal controls over financial reporting, 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.

 

62

---

Table of Contents

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.

 

63

---

Table of Contents

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, 2008			23,667				41,910				30,652
Revisions to previous estimates			(9,183	)			(14,093	)			(11,532	)
Extensions and discoveries			39				1,366				267
Production			(1,755	)			(3,825	)			(2,393	)
Balance, December 31, 2008			12,768				25,358				16,994
Revisions to previous estimates			6,594				13,982				8,924
Extensions and discoveries			—				4				1
Production			(1,572	)			(4,318	)			(2,292	)
Balance, December 31, 2009			17,790				35,026				23,627
Revisions to previous estimates			(572	)			(4,275	)			(1,284	)
Extensions and discoveries			10				15				13
Production			(1,459	)			(3,335	)			(2,015	)
Balance at December 31, 2010			15,769				27,431				20,341
Proved developed reserves:
Balance at December 31, 2007			21,210				32,817				26,679
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
Proved undeveloped reserves:
Balance at December 31, 2007			2,457				9,093				3,973
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

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 2010, revisions to previous estimates decreased proved reserves by a net amount of 1,284 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.

In 2009, revisions to previous estimates increased proved reserves by a net amount of 8,924 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.

In 2008, revisions to previous estimates decreased proved reserves by a net amount of 11,532 MBOE. Included in these revisions were 9,183 MBbl of downward adjustments to crude oil reserves primarily due to lower oil prices of $44.60 per Bbl of oil in reserve estimates at December 31, 2008, as compared to $96.00 per Bbl of oil at December 31, 2007, causing a decrease in the estimated economic life of many of the oil wells. This downward revision in crude oil reserves was accompanied by 14.1 Bcf of net downward adjustments to natural gas reserve quantities, primarily because of the decrease in associated gas volumes that were lost due to the shorter economic lives of many of the oil wells.

 

64

---

Table of Contents

Proved undeveloped reserves.    The estimated volume of proved undeveloped reserves decreased from 3,133 MBOE at December 31, 2009 to 1,489 MBOE at December 31, 2010. This reduction of 1,644 MBOE was due primarily to the drilling of eight proved undeveloped wells in the Keystone, South field. Approximately $10.7 million in capital expenditures, or $11.69 per BOE, was incurred to drill and bring on production for these wells, which had proved undeveloped reserves of 915 MBOE. The reserves for those wells were promoted to the proved developed reserve category as of December 31, 2010. In addition, there were two undeveloped well locations with reserves of 471 MBOE that were removed from the proved undeveloped reserve category on December 31, 2010 due to continuing low gas prices and Whiting’s decision not to drill those wells. All proved undeveloped reserve quantities presented above 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 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

 

65

---

Table of Contents

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 2008, sales to ConocoPhillips, Chevron USA, Plains Marketing LP and Marathon Oil Corporation accounted for 15%, 14%, 11% and 10% , respectively, of total oil and natural gas sales related to the underlying properties. 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. 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;

 

•

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.

 

66

---

Table of Contents

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.

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;

 

67

---

Table of Contents

•

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.

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

 

68

---

Table of Contents

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 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 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 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,

 

69

---

Table of Contents

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. In addition, 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 Drinking Water Act as Class II wells. Such regulation could result in increased costs and operational delays for certain hydraulic fracturing operations.

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.

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

 

70

---

Table of Contents

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.

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 nine month period ended September 30, 2011 with respect to these properties. Additionally, as of the date of this prospectus, it is not aware of any environmental issues or claims that will require material capital expenditures during the remainder of 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.

 

71

---

Table of Contents

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;

 

72

---

Table of Contents

•

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;

 

•

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.

 

73

---

Table of Contents

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 $4,726 per annum for 2010 per active operated well, which totaled $1.8 million for the twelve months ending December 31, 2010 for all of the underlying properties. The fee is adjusted annually pursuant to COPAS guidelines and will increase or decrease each year based on changes in the year-end index of average weekly earnings of crude petroleum and natural gas workers.

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

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

ADDITIONAL PROVISIONS

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

 

•

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

 

•

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

 

•

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

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

 

 

74

---

Table of Contents

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.

 

75

---

Table of Contents

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 18,250,500 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 18,250,500 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.

 

76

---

Table of Contents

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

 

77

---

Table of Contents

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 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.

 

78

---

Table of Contents

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.

 

79

---

Table of Contents

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;

 

80

---

Table of Contents

•

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.

 

81

---

Table of Contents

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 18,250,500 trust units outstanding upon completion of this offering.

DISTRIBUTIONS AND INCOME COMPUTATIONS

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

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

 

82

---

Table of Contents

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.

 

83

---

Table of Contents

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.

 

84

---

Table of Contents

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 18,250,500 trust units. All of the 15,870,000 trust units sold in this offering, or the 18,250,500 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 2,380,500 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, 2,380,500 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.

 

85

---

Table of Contents

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.

 

86

---

Table of Contents

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 2011 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, 2010. See “Where you can find more information” for information relating to where you can find these documents.

 

87

---

Table of Contents

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;

 

88

---

Table of Contents

•

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.

 

89

---

Table of Contents

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.

 

90

---

Table of Contents

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.

 

91

---

Table of Contents

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.

 

92

---

Table of Contents

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).

 

93

---

Table of Contents

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

 

94

---

Table of Contents

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.

 

95

---

Table of Contents

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.

 

96

---

Table of Contents

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

---

Table of Contents

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.

 

98

---

Table of Contents

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.

 

99

---

Table of Contents

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 18,250,500 units, which will be distributed as a dividend to Whiting Petroleum Corporation. Of those trust units, 15,870,000 are being offered hereby and 2,380,500 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., acting as representative 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)			18,250,500				100.0	%			15,870,000				2,380,500				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

---

Table of Contents

UNDERWRITING

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

 

Underwriter		Number of Trust  Units
Raymond James & Associates, Inc.
Total			15,870,000

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 2,380,500 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

$

$

$

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.

 

101

---

Table of Contents

The other expenses of this offering that are payable by Whiting are estimated to be $1.5 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 has agreed with the underwriters, for a period of 180 days after the date of this prospectus, not to offer, sell, contract to sell or otherwise dispose of or transfer any trust units or any securities convertible into or exchangeable for trust units without the prior written consent of Raymond James & Associates, Inc. These agreements also preclude any hedging collar or other transaction designed or reasonably expected to result in a disposition of trust units or securities convertible into or exercisable or exchangeable for trust units. Raymond James & Associates, Inc. may, in its discretion and at any time without notice, release all or any portion of the securities subject to these agreements. Raymond James & Associates, Inc. does not have any present intent or any understanding to release all or any portion of the securities subject to these agreements.

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

 

•

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

 

•

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

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

STABILIZATION

Until this offering is completed, rules of the SEC may limit the ability of the underwriters and various selling group members to bid for and purchase the trust units. As an exception to these rules 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;

 

•

imposition of penalty bids; and

 

•

purchases to cover positions created by short sales.

 

102

---

Table of Contents

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. Additionally, an affiliate of Raymond James & Associates, Inc. is a co-syndication agent and lender under Whiting’s credit agreement and a portion of the proceeds of this offering will be used to repay debt outstanding to this affiliate of Raymond James & Associates, Inc. under Whiting’s credit agreement. 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.

 

103

---

Table of Contents

IPO PRICING

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

 

•

estimates of distributions to trust unitholders;

 

•

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

 

•

industry and market conditions prevalent in the energy industry;

 

•

the information set forth in this prospectus and otherwise available to the representative; and

 

•

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

ELECTRONIC PROSPECTUS

A prospectus in electronic format may be available on the Internet sites or through other online services maintained by one or more of the underwriters and selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the underwriter or the selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with Whiting to allocate a specific number of trust units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

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

FINRA CONDUCT RULES

Because FINRA is expected to view the trust units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA’s Conduct Rules. Investor suitability with respect to the trust units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

 

104

---

Table of Contents

LEGAL MATTERS

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

EXPERTS

The statements of historical revenues and direct operating expenses of the underlying properties for each of the three years in the period ended December 31, 2010, included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such financial statements have been so included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

The statement of assets and trust corpus of Whiting USA Trust II as of December 8, 2011, included in this prospectus has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such financial statements have been so included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

The consolidated financial statements and the related financial statement schedule, incorporated in this prospectus by reference from Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2010, and the effectiveness of Whiting Petroleum Corporation’s internal control over financial reporting have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports, which are incorporated herein by reference (which reports (1) express an unqualified opinion on the financial statements and financial statement schedule and includes an explanatory paragraph relating to the Company’s adoption of new accounting guidance and (2) express an unqualified opinion on the effectiveness of internal control over financial reporting). Such financial statements and financial statement schedule have been so incorporated in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

Certain information appearing in this prospectus regarding the December 31, 2011 estimated quantities of reserves of the underlying properties and net profits interest owned by the trust, the future net revenues from those reserves and their present value is based on estimates of the reserves and present values prepared by or derived from estimates prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers.

Certain information with respect to Whiting’s oil and natural gas reserves derived from the report of Cawley Gillespie & Associates, Inc., an independent petroleum engineering consultant, has been incorporated in this prospectus by reference from Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year-ended December 31, 2010 as amended by its Annual Report on Form 10-K/A, on the authority of said firm as an expert in petroleum engineering.

 

105

---

Table of Contents

WHERE YOU CAN FIND MORE INFORMATION

The trust and Whiting have filed with the SEC a registration statement on Form S-1 and Form S-3 regarding the trust units. This prospectus does not contain all of the information found in the registration statement. For further information regarding the trust, Whiting and the trust units offered by this prospectus, you may wish to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a website on the Internet at http://www.sec.gov. The trust’s and Whiting’s registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

Whiting files annual, quarterly and current reports, proxy statements and other information with the SEC) (File No. 001-31899) pursuant to the Exchange Act. Whiting’s SEC filings are available to the public through the SEC’s website.

This prospectus includes through incorporation by reference certain of the reports and other information that Whiting has filed with the SEC. This means that Whiting is disclosing important information to you by referring to those documents. The information that Whiting later files with the SEC is incorporated by reference herein and will automatically update and supersede this information. Whiting hereby incorporates by reference into this prospectus the documents listed below that Whiting has filed with the SEC:

 

•

Whiting’s Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on February 24, 2011, as amended by Whiting’s Amendment No. 1 on Form 10-K/A to its Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on March 3, 2011;

 

•

Whiting’s Proxy Statement on Schedule 14A, filed with the SEC on April 1, 2011;

 

•

Whiting’s Quarterly Report on Form 10-Q for each of the quarters ended March 31, 2011, June 30, 2011 and September 30, 2011; and

 

•

Whiting’s Current Reports on Form 8-K, dated January 17, 2011, May 3, 2011, October 12, 2011 and January 17, 2012.

Whiting also hereby incorporates by reference into this prospectus any filings that it makes with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act (excluding any information furnished under Item 2.02 or Item 7.01 on any Current Report on Form 8-K) after the filing of the registration statement to which this prospectus relates and prior to the effectiveness of such registration statement, and all such future filings that it makes with the SEC prior to the later of (a) the closing date of the offering and (b) the completion of the offering of the trust units.

Whiting’s recent annual, quarterly and current reports, and any amendments thereto, that it files with the SEC are made available, free of charge, over the Internet through Whiting’s website at http:www.whiting.com as soon as reasonably practicable after Whiting electronically files them with or furnishes them to the SEC. You may also request copies of any of Whiting’s filings with the SEC, which it will provide at no cost to you, by contacting Whiting’s Investor Relations department at 303-837-1661. Please note that Whiting’s website and the information contained in and linked to it are not incorporated in this prospectus.

 

106

---

Table of Contents

GLOSSARY OF CERTAIN DEFINITIONS

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

Bbl — One stock tank barrel, or 42 U.S. gallons liquid volume, used in this prospectus in reference to oil and other liquid hydrocarbons.

Bcf — One billion cubic feet of natural gas.

Bcfe — One billion cubic feet of natural gas equivalent.

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

BOE/d — One BOE per day.

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

Completion — The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

COPAS — The Council of Petroleum Accountants Societies, Inc.

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

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

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

FASB — The Financial Accounting Standards Board.

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

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

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

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

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

 

107

---

Table of Contents

MBOE — One thousand BOE.

Mcf — One thousand standard cubic feet of natural gas.

MMBbl — One million Bbl.

MMBOE — One million BOE.

MMBtu — One million Btu.

MMcf — One million standard cubic feet of natural gas.

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

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

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

Plugging and Abandonment — Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.

Pre-tax PV10% — The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with the guidelines of the SEC, net of estimated lease operating expense, production taxes and future development costs, using price and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or Federal income taxes and discounted using an annual discount rate of 10%. Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC.

Proved Developed Non-producing Reserves — Proved developed reserves expected to be recovered from zones behind casing in existing wells.

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

Proved Developed Reserves — Proved reserves that can be expected to be recovered 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.

Proved Reserves — Those reserves 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.

 

108

---

Table of Contents

The area of the reservoir considered as proved includes all of the following:

 

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.

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur:

 

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.

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 before 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.

Proved Undeveloped Reserves — Proved reserves 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.

Recompletion — An operation whereby a completion in one zone is abandoned in order to attempt a completion in a different zone within the existing wellbore.

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

SEC — The United States Securities and Exchange Commission.

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

The Financial Accounting Standards Board requires disclosure of standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities, per paragraph 30 of FASB ASC Topic 932-235, Extractive Activities — Oil and Gas, as follows:

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

 

a.

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

 

109

---

Table of Contents

b.

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

 

c.

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

 

d.

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

 

e.

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

 

f.

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

Working Interest — The interest in a crude oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.

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

 

110

---

Table of Contents

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, 2010, and the Nine Months Ended September 30, 2010 and 2011 (unaudited)			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 8, 2011			F-15
Unaudited Pro Forma Statements of Distributable Income for the Year Ended December  31, 2010, and for the Nine Months Ended September 30, 2011			F-16
Notes to Unaudited Pro Forma Financial Information			F-17

 

F-1

---

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Whiting Petroleum Corporation

Denver, Colorado

We have audited the accompanying statements of historical revenues and direct operating expenses of the Underlying Properties (the “Properties”) of Whiting Petroleum Corporation (the “Company”) for each of the three years in the period ended December 31, 2010. These statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these statements based on our audits.

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

The accompanying statements were prepared 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 the Company’s interests in the Properties.

In our opinion, the statements referred to above present fairly, in all material respects, the historical revenues and direct operating expenses of the Properties for each of the three years in the period ended December 31, 2010, on the basis of accounting discussed in Note 2 to the financial statements.

/s/ Deloitte & Touche LLP

Denver, Colorado

December 16, 2011

 

F-2

---

Table of Contents

UNDERLYING PROPERTIES

STATEMENTS OF HISTORICAL REVENUES

AND DIRECT OPERATING EXPENSES

(In thousands)

 

		Year Ended December 31,												Nine Months  Ended September 30,
		2008				2009				2010				2010				2011
														(unaudited)
Revenues:
Oil sales		$	159,243			$	85,826			$	104,667			$	77,013			$	90,711
Natural gas sales			34,924				19,791				19,041				14,499				12,537
Total revenues			194,167				105,617				123,708				91,512				103,248
Direct operating expenses:
Lease operating			35,106				31,935				33,876				24,641				27,287
Production tax			10,992				5,718				6,571				5,117				5,675
Total direct operating expenses			46,098				37,653				40,447				29,758				32,962
Excess of revenues over direct operating expenses		$	148,069			$	67,964			$	83,261			$	61,754			$	70,286

The accompanying notes are an integral part of this statement.

 

F-3

---

Table of Contents

UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF HISTORICAL REVENUES

AND DIRECT OPERATING EXPENSES

For the years ended December 31, 2008, 2009 and 2010

(Information for the nine months ended September 30, 2010 and 2011 is unaudited)

1. UNDERLYING PROPERTIES

The accompanying statements present the revenues and direct operating expenses for the years ended December 31, 2008, 2009 and 2010 and the nine months ended September 30, 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 property taxes. The amounts presented represent 100% of Whiting’s interests in 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. Financial information for the nine months ended September 30, 2010 has been presented on a basis consistent with the financial information for the nine months ended September 30, 2011 in order to provide comparability between periods presented. 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

---

Table of Contents

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, 2010, 2009 and 2008:

 

		2010				2009				2008
Chevron USA			13	%			13	%			14	%
ConocoPhillips			13	%			13	%			15	%
Marathon Oil Corporation			11	%			11	%			10	%
Plains Marketing, LP			14	%			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.

Interim Financial Statements.    The accompanying statements of historical revenues and direct operating expenses for the nine months ended September 30, 2010 and 2011 are unaudited and should be read in conjunction with the financial statements for the years ended December 31, 2008, 2009 and 2010. Such interim financial statements have been prepared on the same basis as the annual statements of historical revenues and direct operating expenses, as stated above. In the opinion of management, these accompanying interim financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the results of the underlying properties for the interim periods presented. However, the operating results for such interim periods presented are not necessarily indicative of the results that may be expected for the full year.

3. SUBSEQUENT EVENTS

Events occurring after December 31, 2010 were evaluated through 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

---

Table of Contents

As of December 31, 2010, 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, 2010, 2009 and 2008, are as follows:

 

		Oil (MBbl)				Natural Gas (MMcf)				Total MBOE
Balance — January 1, 2008			23,667				41,910				30,652
Revisions to previous estimates			(9,183	)			(14,093	)			(11,532	)
Extensions and discoveries			39				1,366				267
Production			(1,755	)			(3,825	)			(2,393	)
Balance — December 31, 2008			12,768				25,358				16,994
Revisions to previous estimates			6,594				13,982				8,924
Extensions and discoveries			—				4				1
Production			(1,572	)			(4,318	)			(2,292	)
Balance — December 31, 2009			17,790				35,026				23,627
Revisions to previous estimates			(572	)			(4,275	)			(1,284	)
Extensions and discoveries			10				15				13
Production			(1,459	)			(3,335	)			(2,015	)
Balance — December 31, 2010			15,769				27,431				20,341
Proved developed reserves:
December 31, 2007			21,210				32,817				26,679
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
Proved undeveloped reserves:
December 31, 2007			2,457				9,093				3,973
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

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 1,284 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 8,924 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.

 

F-6

---

Table of Contents

Notable changes in proved reserves for the year ended December 31, 2008 included:

 

•

Revisions to previous estimates. In 2008, revisions to previous estimates decreased proved reserves by a net amount of 11,532 MBOE. Included in these revisions were 9,183 MBbl of downward adjustments to crude oil reserves primarily due to lower oil prices of $44.60 per Bbl of oil in reserve estimates at December 31, 2008, as compared to $96.00 per Bbl of oil at December 31, 2007, causing a decrease in the estimated economic life of many of the oil wells. This downward revision in crude oil reserves was accompanied by 14.1 Bcf of net downward adjustments to natural gas reserve quantities, primarily due to the decrease in associated gas volumes that were lost because of the shorter economic lives of many of the oil wells.

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 period ended December 31, 2010 and 2009, respectively) to estimated future production. Future cash inflows as of December 31, 2008, however, were computed by applying prices at year-end to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming the continuation of existing economic conditions. No provision for federal or state income taxes has been provided in the standardized measure of discounted future net cash flows 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,
		2010				2009				2008
Future cash inflows		$	1,243,215			$	1,080,650			$	600,460
Future production costs			(538,019	)			(462,024	)			(298,573	)
Future development costs			(17,956	)			(39,146	)			(20,802	)
Future net cash flows		$	687,240			$	579,480			$	281,085
10% annual discount for estimated timing of cash flows			(296,299	)			(247,472	)			(112,835	)
Standardized measure of discounted future net cash flows (1)		$	390,941			$	332,008			$	168,250

 

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

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,
		2010				2009				2008
Beginning of year		$	332,008			$	168,250			$	831,338
Sale of oil and gas produced, net of production costs			(83,261	)			(67,964	)			(148,069	)
Net changes in prices and production costs			127,167				95,347				(507,485	)
Extensions and discoveries less related costs			231				11				2,508
Previously estimated development costs incurred during the period			39,146				20,229				25,968
Changes in estimated future development costs			(34,086	)			(29,262	)			(10,706	)
Revisions of previous quantity estimates			(23,465	)			128,572				(108,438	)
Accretion of discount			33,201				16,825				83,134
End of year		$	390,941			$	332,008			$	168,250

 

F-7

---

Table of Contents

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, 2010, 2009 and 2008 as follows:

 

		2010				2009				2008
Oil (per Bbl)		$	72.84			$	54.92			$	36.97
Gas (per Mcf)		$	5.96			$	4.40			$	6.34

 

F-8

---

Table of Contents

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

 

F-9

---

Table of Contents

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.

 

F-10

---

Table of Contents

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;

 

F-11

---

Table of Contents

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.

 

F-12

---

Table of Contents

3. SUBSEQUENT EVENTS

Events occurring after December 8, 2011 were evaluated through 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

---

Table of Contents

WHITING USA TRUST II

UNAUDITED PRO FORMA FINANCIAL INFORMATION

The following unaudited pro forma statement of assets and trust corpus and unaudited pro forma statements of distributable income for the Trust have been prepared to illustrate the conveyance of the term net profits interest in the underlying properties to the Trust by Whiting Oil and Gas Corporation. The unaudited pro forma statement of assets and trust corpus presents the formation of the Trust as if it had occurred on September 30, 2011, and giving effect to the net profits interest conveyance as if it occurred on that date. The unaudited pro forma statements of distributable income for the year ended December 31, 2010 and the nine months ended September 30, 2011, give effect to the Trust formation and net profits interest conveyance as if they occurred as of the beginning of the earliest period presented, 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 periods 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 statements 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.

 

F-14

---

Table of Contents

WHITING USA TRUST II

UNAUDITED PRO FORMA STATEMENT OF ASSETS AND TRUST CORPUS

September 30, 2011

 

		Historical				Adjustments				Pro Forma
ASSETS
Cash and short-term investments		$	10			$	—			$	10
Investment in Net Profits Interest (Note 5)			—				167,117,240	(a)			167,117,240
		$	10			$	167,117,240			$	167,117,250
TRUST CORPUS
18,250,500 Trust units issued and outstanding (Note 5)		$	10			$	167,117,240	(a)		$	167,117,250

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

 

F-15

---

Table of Contents

WHITING USA TRUST II

UNAUDITED PRO FORMA STATEMENTS OF DISTRIBUTABLE INCOME

 

		Year Ended December 31, 2010				Nine Months Ended September 30, 2011
Historical results
Income from Net Profits Interest		$	50,177,188			$	50,959,144
Pro Forma Adjustments
Less:
Trust general and administrative expenses (Note 5)			(375,000	)(b)			(281,250	)(b)
State income tax withholdings (Note 5)			(77,380	)(c)			(73,783	)(c)
Distributable income		$	49,724,808			$	50,604,111
Distributable income per unit (Note 5)		$	2.72	(d)		$	2.77	(d)

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

 

F-16

---

Table of Contents

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 September 30, 2011. The unaudited pro forma statements of distributable income assume the conveyance of the net profits interest and Trust formation as of the beginning of the earliest period presented.

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 statements of distributable income were 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. These unaudited pro forma statements were 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 statements purport to show distributable income, defined as income of the Trust available for distribution to the Trust unitholders before application of those unitholders’ additional expenses, if any, for depreciation, depletion and amortization, interest and income taxes. Revenues are reflected net of existing royalties and overriding

 

F-17

---

Table of Contents

royalties associated with Whiting’s interests. While these statements differ 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, 2010				Nine Months Ended September 30, 2011
Excess of revenues over direct operating expenses of underlying properties		$	83,260,327			$	70,286,803
Adjust from accrual basis of accounting to modified cash basis(1)(2)			(510,238	)			81,783
Modified cash basis excess revenues over direct operating expenses			82,750,089				70,368,586
Development costs on a modified cash basis			(26,997,658	)			(13,747,315	)
Total net proceeds			55,752,431				56,621,271
Times the term NPI percentage			90	%			90	%
Income from net profits interest		$	50,177,188			$	50,959,144

 

(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 the nine months ended September 30, 2011 would have been made by August 29, 2011 (covering net cash proceeds received by Whiting for oil sales through June 30, 2011 and gas sales through May 31, 2011) and the last

 

F-18

---

Table of Contents

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 July, August and September of 2011, (ii) exclude net cash proceeds attributable to natural gas sales for June, July, August and September 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.

(2)

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 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) and the last quarterly distribution for 2009 would have been made by November 29, 2009 (covering net cash proceeds received by Whiting for oil sales through September 30, 2009 and gas sales through August 31, 2009). 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 2010, (ii) exclude net cash proceeds attributable to natural gas sales for September, October, November and December of 2010, (iii) include net proceeds attributable to oil sales for October, November and December of 2009, and (iv) include net proceeds attributable to natural gas sales for September, October, November and December of 2009.

5. PRO FORMA ADJUSTMENTS

(a) Whiting will convey the net profits interest to the Trust in exchange for 18,250,500 trust units.

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

 

Oil and gas properties		$	356,494,947
Accumulated depreciation and depletion			(170,809,125	)
Net predecessor cost of net profits interest conveyed to the Trust		$	185,685,822
Times 90% net profits interest to Trust		$	167,117,240

(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 statements of distributable income, the distributable income would be $49,060,724 or $2.69 per unit and $50,135,206 or $2.75 per unit, respectively, for the periods ended December 31, 2010 and September 30, 2011. Due to the omission of general and administrative expenses other than the $375,000 administrative fee from the unaudited pro forma statements of distributable income, these pro forma financial statements 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 18,250,500 trust units.

 

F-19

---

Table of Contents

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

 

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

 

A-1

---

Table of Contents

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.

 

A-2

---

Table of Contents

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.

 

A-3

---

Table of Contents

Whiting USA Trust II

December 9, 2011

Page 4

 

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

 

A-4

---

Table of Contents

Whiting USA Trust II

December 9, 2011

Page 5

 

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.

 

A-5

---

Table of Contents

Whiting USA Trust II

December 9, 2011

Page 6

 

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.

 

A-6

---

Table of Contents

Whiting USA Trust II

December 9, 2011

Page 7

 

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

 

A-7

---

Table of Contents

Whiting USA Trust II

December 9, 2011

Page 8

 

“(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

 

A-8

---

Table of Contents

Whiting USA Trust II

December 9, 2011

Page 9

 

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).”

 

A-9

---

Table of Contents

Whiting USA Trust II

December 9, 2011

Page 10

 

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.

 

A-10

---

Table of Contents

 

 

 

15,870,000 Trust Units

WHITING USA TRUST II

 

 

 

PROSPECTUS

 

 

 

RAYMOND JAMES

                    , 2012

 

 

 

 

---

Table of Contents

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		$	44,121
FINRA filing fee			39,000
NYSE listing fee			125,000
Printing and engraving expenses			200,000
Fees and expenses of legal counsel			800,000
Accounting fees and expenses			200,000
Transfer agent and registrar fees			2,500
Trustee fees and expenses			3,500
Miscellaneous			85,879
Total		$	1,500,000

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

 

II-1

---

Table of Contents

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.

 

II-2

---

Table of Contents

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.

 

II-3

---

Table of Contents

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 January 30, 2012.

 

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 January 30, 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

---

Table of Contents

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 January 30, 2012.

 

 

S-2

---

Table of Contents

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

---

Table of Contents

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).

 

*	To be filed by amendment.

†	Previously filed.

 

E-2