Whiting USA Trust II (WHZT) 10-K 2013 FY Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

[ü] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

for The Fiscal Year Ended December 31, 2013

[    ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

for the transition period from                 to                

Commission File Number 001-35459

WHITING USA TRUST II

(Exact name of registrant as specified in its charter)

Delaware	38-7012326
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
The Bank of New York Mellon Trust Company, N.A., Trustee	78701 (Zip Code)
Global Corporate Trust 919 Congress Avenue Austin, Texas
(Address of principal executive offices)

Registrant’s telephone number, including area code: (512) 236-6545

Securities registered pursuant to Section 12(b) of the Act:

Units of Beneficial Interest	New York Stock Exchange
Title of Each Class	Name of Each Exchange on which Registered

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes            No     ü    .

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes            No    ü    .

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes    ü    No            

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes            No            

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ü    

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):

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes            No    ü    

The aggregate market value of Units of Beneficial Interest in Whiting USA Trust II held by non-affiliates at the closing sales price on June 30, 2013 of $12.88 was $236,992,000.

As of March 13, 2014, 18,400,000 Units of Beneficial Interest in Whiting USA Trust II were outstanding.

Documents Incorporated By Reference: None

TABLE OF CONTENTS

Forward-Looking Statements	2
Glossary of Certain Definitions	3
PART I
Item 1.Business	8
Item 1A.Risk Factors	21
Item 1B.Unresolved Staff Comments	35
Item 2.Properties	35
Item 3.Legal Proceedings	42
Item 4.Mine Safety Disclosures	42
PART II
Item 5.Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	43
Item 6.Selected Financial Data	44
Item 7.Trustee’s Discussion and Analysis of Financial Condition and Results of Operations	44
Item 7A.Quantitative and Qualitative Disclosure About Market Risk	56
Item 8.Financial Statements and Supplementary Data	58
Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	78
Item 9A.Controls and Procedures	78
Item 9B.Other Information	81
PART III
Item 10.Directors, Executive Officers and Corporate Governance	81
Item 11.Executive Compensation	81
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	82
Item 13.Certain Relationships and Related Transactions and Director Independence	82
Item 14.Principal Accountant Fees and Services	83
PART IV
Item 15.Exhibits and Financial Statement Schedules	84

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References to the “Trust” in this document refer to Whiting USA Trust II. References to “Whiting” in this document refer to Whiting Petroleum Corporation and its subsidiaries. References to “Whiting Oil and Gas” in this document refer to Whiting Oil and Gas Corporation, a wholly-owned subsidiary of Whiting Petroleum Corporation.

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this Form 10-K, including without limitation the statements under “Trustee’s Discussion and Analysis of Financial Condition and Results of Operation” are forward-looking statements. No assurance can be given that such expectations will prove to have been correct. When used in this document, the words “believes,” “expects,” “anticipates,” “intends” or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this Form 10-K, could affect the future results of the energy industry in general, 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;

• inflation or deflation; and

• other risks described under the caption “Risk Factors” in this Form 10-K.

This Form 10-K describes other important factors that could cause actual results to differ materially from expectations of Whiting and the Trust, including under the caption “Risk Factors.” All subsequent 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. The Trust assumes no obligation, and disclaims any duty, to update these forward-looking statements.

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GLOSSARY OF CERTAIN DEFINITIONS

In this Form 10-K the following terms have the meanings specified below.

“August 2012 distribution”The cash distribution to Trust unitholders of record on August 20, 2012 that was paid on August 28, 2012.

“August 2013 distribution”The cash distribution to Trust unitholders of record on August 19, 2013 that was paid on August 29, 2013.

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

“Bcf” One billion cubic feet of natural gas.

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

“BOE/d” One BOE per day.

“Btu” or “British thermal unit” The quantity of heat required to raise the temperature of one pound of water one degree Fahrenheit.

“CO₂” Carbon dioxide.

“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.

“deterministic method” The method of estimating reserves or resources using a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation.

“development well” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

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

“exploratory well” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.

“extension well” A well drilled to extend the limits of a known reservoir.

“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.”

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“FASB” Financial Accounting Standards Board.

“FASB ASC” The Financial Accounting Standards Board Accounting Standards Codification.

“February 2013 distribution” The cash distribution to Trust unitholders of record on February 19, 2013 that was paid on March 1, 2013.

“February 2014 distribution” The cash distribution to Trust unitholders of record on February 19, 2014 that was paid on March 3, 2014.

“field” An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest, etc.

“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.

“IRS” The Internal Revenue Service of the United States federal government.

“lease operating expense”or “LOE” The expenses of lifting oil or gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.

“May 2012 distribution”The cash distribution to Trust unitholders of record on May 20, 2012 (which resulted in an actual effective record date of May 18, 2012 due to May 20^th falling on a non-trading day) that was paid on May 30, 2012.

“May 2013 distribution”The cash distribution to Trust unitholders of record on May 20, 2013 that was paid on May 30, 2013.

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

“MBOE” One thousand BOE.

“MBOE/d” One MBOE per day.

“Mcf” One thousand standard cubic feet, used in reference to natural gas.

“MMBOE” One million BOE.

“MMBtu” One million Btu.

“MMcf” One million standard cubic feet, used in reference to natural gas.

“net acres or net wells” The sum of the fractional working interests owned in gross acres or wells, as the case may be.

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“net production” The total production attributable to our fractional working interest owned.

“net profits interest” or “NPI” 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.

“November 2012 distribution”The cash distribution to Trust unitholders of record on November 19, 2012 that was paid on November 29, 2012.

“November 2013 distribution”The cash distribution to Trust unitholders of record on November 19, 2013 that was paid on November 29, 2013.

“NYMEX” The New York Mercantile Exchange.

“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 costs as of the date of estimation without future escalation and using an average of the first-day-of-the-month price for each of the 12 months within the period, 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 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.

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.

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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. 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. 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 specific circumstances justify a longer time. Under no circumstances shall estimates for proved 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, or by other evidence using reliable technology establishing reasonable certainty.

“reasonable certainty” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical), engineering and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

“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.

“reserves”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.

“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.

“royalty” The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from crude oil or natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.

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“royalty interest” An interest in an oil or natural gas property entitling the owner to shares of the crude oil or natural gas production free of costs of exploration, development and production operations.

“SEC” The U.S. Securities and Exchange Commission.

“service well”A service well is a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation or injection for in-situ combustion.

“standardized measure of discounted future net cash flows” Also referred to herein as “standardized measure.” The discounted future net cash flows relating to proved reserves based on 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); current costs and statutory tax rates (to the extent applicable); and a 10% annual discount rate.

“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 to share in production, subject to all royalties, overriding royalties and other burdens and the obligation to share in all costs of exploration, development and operations and all risks in connection therewith.

“workover” Operations on a producing well to restore or increase production.

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P A R T    I

Item 1.    Business

General

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, as Delaware Trustee (the “Delaware Trustee”). The initial capitalization of the Trust estate was funded by Whiting Petroleum Corporation (“Whiting”) on December 8, 2011. The Trust maintains its offices at the office of the Trustee, at 919 Congress Avenue, Austin, Texas 78701. The telephone number of the Trustee is 512-236-6545.

The Trust makes copies of its reports under the Exchange Act available athttp://whitingwhz.investorhq.businesswire.com. The Trust’s filings under the Exchange Act are also available electronically from the website maintained by the SEC athttp://www.sec.gov. In addition, the Trust will provide electronic and paper copies of its recent filings free of charge upon request to the Trustee.

As of December 31, 2011, the Trust had no assets other than a de minimis cash balance from its initial capitalization and had conducted no operations other than organizational activities. In March 2012, the Trust issued 18,400,000 units of beneficial interest in the Trust (“Trust units”) to Whiting in exchange for the conveyance of a term NPI by Whiting Oil and Gas. The NPI represents the right for the Trust to receive 90% of the net proceeds from Whiting’s interests in certain existing oil, natural gas and natural gas liquid producing properties which we refer to as “the underlying properties”. The underlying properties are located in the Rocky Mountains, Permian Basin, Gulf Coast and Mid-Continent regions. The underlying properties include interests in 1,308 gross (388.5 net) producing oil and gas wells. Whiting completed an initial public offering of Trust units selling all of its 18,400,000 units on March 28, 2012.

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 amount 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, after which it will pay no further distributions and the market price of Trust units will have declined to zero.

As of December 31, 2013, on a cumulative accrual basis 3.18 MMBOE (30%) of the Trust’s total 10.61 MMBOE have been produced and sold. Further detail on the reserves is provided herein under the section titled “Properties-Description of the Underlying Properties — Reserves”, and such reserve information is based upon a reserve report prepared by independent reserve engineers Cawley, Gillespie & Associates, Inc. for the underlying properties at December 31, 2013, which we refer to as the “reserve report.” According to the reserve report, the portion of the 11.79 MMBOE (10.61 MMBOE at the 90% NPI) reserve quantities attributable to the NPI not yet produced or sold as divestitures at December 31, 2013 is projected to be produced from the underlying properties prior to December 31, 2021, and the reserve report is based on the assumptions included therein. See “Risk Factors” in Item 1A of this Annual Report on Form 10-K for additional discussion. Production from the underlying properties for the year ended December 31, 2013 was approximately 77% oil and approximately 23% natural gas.

Net proceeds payable to the Trust depend upon production quantities; sales prices of oil, natural gas and natural gas liquids; costs to develop and produce the oil and gas; and realized cash settlements from commodity derivative contracts. In calculating net proceeds, Whiting deducts from gross oil and natural gas sales proceeds, lease operating expenses (including costs of workovers), production and property taxes, development costs, hedge payments made by Whiting to the hedge contract counterparty, maintenance expenses, producing overhead

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(all such costs, “production and development costs”) and amounts that may be reserved for future development, maintenance or operating expenses (which reserve may not exceed $2.0 million at any time) as calculated on an aggregate basis for all these properties. If at any time production and development costs should exceed gross proceeds, neither the Trust nor the Trust unitholders would be liable for the excess costs. The Trust however, would not receive any net proceeds until future net proceeds exceed the total of those excess costs, plus interest at the prevailing money market rate. For more information on the net proceeds calculation, see “Computation of Net Proceeds” later in this section.

The Trust makes quarterly cash distributions of substantially all of its quarterly cash receipts, after the deduction of fees and expenses for the administration of the Trust, to holders of its Trust units. Because payments to the Trust are generated by depleting assets and the Trust has a finite life due to the production from the underlying properties diminishing over time, a portion of each distribution represents a return of the original investment in the Trust units, with the remainder being considered as a return on investment. As a result, the market price of the Trust units will decline to zero at termination 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, 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, which may be a non-interest bearing account, and make other short-term investments with the funds distributed to the Trust.

The Trust was created to acquire and hold the term NPI for the benefit of the Trust unitholders pursuant to the conveyance to the Trust from Whiting Oil and Gas. The NPI is the only asset of the Trust, other than cash held for Trust expenses. The NPI is passive in nature, and the Trustee has no management control over and no responsibility relating to the operation of the underlying properties. The business and affairs of the Trust are administered by the Trustee, and Whiting and its affiliates have no ability to manage or influence the operations of the Trust. The oil and gas properties comprising the underlying properties for which Whiting is designated the operator are currently operated by Whiting and its subsidiaries on a contract operator basis. Whiting, as a matter of course, does not make public projections as to future sales, earnings or other results relating to the underlying properties.

Marketing and Major Customers

Pursuant to the terms of the conveyance creating the NPI, Whiting has the responsibility to market, or cause to be marketed, the oil, natural gas and natural gas liquid production attributable to the underlying properties. The terms of the conveyance creating the NPI 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 NPI is calculated. As a result, the net proceeds to the Trust from the sales of oil, natural gas and natural gas liquid production from the underlying properties are determined based on the same price that Whiting receives for oil, natural gas and natural gas liquid production attributable to Whiting’s remaining interest in the underlying properties.

Whiting principally sells its oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is trucked to storage facilities. Whiting’s marketing of oil and natural gas can be affected by factors beyond its control, the effects of which cannot be accurately predicted. During 2013, sales to Chevron USA, Plains Marketing LP, Phillips 66 Company and Marathon Oil Company accounted for 15%, 14%, 12% and 11%, respectively, of total oil and natural gas sales from the underlying properties. Whiting does not believe that the potential loss of any of these purchasers presents 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 the underlying properties were to lose any of their largest purchasers, several entities could reasonably be expected to purchase crude oil and natural gas produced from the underlying properties with little or no interruption to their sales.

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Competition and Markets

The oil and natural gas industry is highly competitive. Whiting competes with major oil and gas companies and independent oil and 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 cash flow. The Trust is 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 NPI 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.

Description of Trust Units

Each Trust unit is a unit of 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 are in book-entry form only and are not represented by certificates.

Periodic Reports

The Trustee files all required Trust federal and state income tax and information returns. The Trustee prepares and mails to Trust unitholders annual reports that Trust unitholders need to correctly report their share of the Trust’s income and deductions. The Trustee also causes to be prepared and filed reports required 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 is responsible for causing 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 or her representatives may examine, for any proper purpose, during reasonable business hours, the records of the Trust and the Trustee.

Liability of Trust Unitholders

Under the Delaware Statutory Trust Act, Trust unitholders are 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 would 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 is 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 are responsible for all costs associated with calling such meeting. 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

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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 $1.0 million for the last twelve months; or

• agree to amend or terminate the conveyance.

In addition, certain amendments to the Trust agreement, conveyance and administrative services agreement may be made by the Trustee without approval of the Trust unitholders.

Termination of the Trust; Sale of the Net Profits Interest

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 amount 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, after which it will pay no further distributions and the market price of Trust units will have declined to zero. The remaining reserve quantities are projected to be produced prior to December 31, 2021, based on the Trust’s reserve report as of December 31, 2013. Since the Trust is not currently expected to contractually terminate until December 31, 2021, additional reserves and production attributable to the NPI may be available for distribution to unitholders (also based on the year-end reserve report) between the time that the Trust’s minimum 10.61 MMBOE have been produced and sold and the expected December 31, 2021 termination date of the Trust occurs. However, there is no assurance that this will occur. The Trust will dissolve prior to the termination of the NPI if:

• the Trust sells the NPI;

• annual cash proceeds to the Trust attributable to the NPI are less than $2.0 million for each of any two consecutive years;

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

• the Trust is judicially dissolved.

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.

Computation of Net Proceeds

The provisions of the conveyance governing the computation of net proceeds are detailed and extensive. The following information summarizes the material information contained in the conveyance related to the

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computation of net proceeds. For more detailed provisions concerning the NPI, we make reference to the conveyance agreement, which is filed as an exhibit to this Annual Report on Form 10-K.

Net Profits Interest

The term NPI was conveyed to the Trust by Whiting Oil and Gas on March 28, 2012 by means of a conveyance instrument that has been recorded in the appropriate real property records in each county where the underlying properties are located. The NPI burdens the interests owned by Whiting in the underlying properties.

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

The amounts paid to the Trust for the NPI 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 are paid to the Trust no later than 60 days following the end of the computation period (or the next succeeding business day). Whiting does not pay to the Trust any interest on the net proceeds held by Whiting prior to payment to the Trust. The Trustee makes distributions to Trust unitholders quarterly.

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

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

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

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

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

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

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• 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 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 may 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 11.79 MMBOE (10.61 MMBOE at the 90% NPI) have been produced from the underlying properties and sold, which is the time when the NPI 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 amount is the equivalent of 7.41 MMBOE in respect of the NPI) (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.

Pursuant to the terms of its applicable joint operating agreements, Whiting deducts from gross 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, as is customary in the oil and gas industry. Operating overhead activities include various engineering, legal and administrative functions. The Trust’s portion of the monthly charge averaged $431 per month per active operated well, which totaled $1.7 million for the four distributions made during the year ended December 31, 2013. 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.

Commodity Hedge Contracts

Whiting entered into certain costless collar hedge contracts, and Whiting in turn conveyed to the Trust the rights and obligations to future hedge payments Whiting makes or receives under such costless collar hedge

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contracts. These contracts were entered into to reduce the exposure to volatility in the underlying properties’ oil revenues due to fluctuations in crude oil prices, and to achieve more predictable cash flows. Historically, prices received for oil production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general economic conditions. Costless collars are designed to establish floor and ceiling prices on anticipated future production. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The hedge contracts are placed with a single trading counterparty, JPMorgan Chase Bank National Association. Whiting cannot provide assurance that this trading counterparty will not become a credit risk in the future. No additional hedges are allowed to be placed on Trust assets, and the Trust cannot therefore enter into derivative contracts for speculative or trading purposes.

Crude oil costless collar arrangements settle based on the average of the closing 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 hedge counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price.

Any 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. Any amounts paid by Whiting upon settlement of the hedge contracts will reduce the amount of net proceeds paid to the Trust. The hedge contracts cover only a portion of anticipated production and apply only to production through December 31, 2014. Whiting’s crude oil price risk management positions in collar arrangements through December 31, 2014 are detailed in “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of this Annual Report on Form 10-K.

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 Whiting 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 NPI. 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

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NPI. Any net sales proceeds paid to the Trust are distributable to Trust unitholders in the quarter in which they are received. During 2013, Whiting had no divestitures of Trust properties.

For the underlying properties for which Whiting is the designated operator, it may enter into farm-out, operating, participation and other similar agreements with respect to the property. Whiting may enter into any of these agreements without the consent or approval of the Trustee or any Trust unitholder.

Whiting or any other operator has 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 NPI. Upon termination of the lease, the portion of the NPI relating to the abandoned property will be extinguished.

Whiting must maintain books and records sufficient to determine the amounts payable under the NPI to the Trust. Quarterly and annually, Whiting must deliver to the Trustee a statement of the computation of 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.

Federal Income Tax Matters

The following is a summary of certain U.S. federal income tax matters that may be relevant to the Trust unitholders. This summary is based upon current provisions of the Internal Revenue Code of 1986, as amended, which we refer to as the “Code,” existing (and to the extent 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. No attempt has been made in the following summary to comment on all U.S. federal income tax matters affecting the Trust or the Trust unitholders.

The summary is limited to Trust unitholders who are individual citizens or residents of the United States. Accordingly, the following summary has limited application to domestic corporations and persons subject to specialized federal income tax treatment such as, without limitation, tax-exempt organizations, regulated investment companies, insurance companies, and foreign persons or entities.Each Trust unitholder should consult his own tax advisor with respect to his particular circumstances.

Classification and Taxation of the Trust

Tax counsel to the Trust advised the Trust at the time of formation that, for U.S. federal income tax purposes, in its opinion, the Trust would be treated as a grantor trust and not as an unincorporated business entity. No ruling has been or will be requested from the IRS or another taxing authority. The remainder of the discussion below is based on tax counsel’s opinion, at the time of formation, that the Trust will be classified as a grantor trust for U.S. federal income tax purposes. As a grantor trust, the Trust is not subject to U.S. federal income tax at the Trust level. Rather, each Trust unitholder is considered for federal income tax purposes to own and receive its proportionate share of the Trust’s assets directly as though no Trust were in existence. The income of the Trust is deemed to be received or accrued by the Trust unitholder at the time such income is received or accrued by the Trust, rather than when distributed by the Trust. Each Trust unitholder is subject to tax on its proportionate share of the income and gain attributable to the assets of the Trust and is entitled to claim its proportionate share of the deductions and expenses attributable to the assets of the Trust, subject to applicable limitations, in accordance with the Trust unitholder’s tax method of accounting and taxable year without regard to the taxable year or accounting method employed by the Trust.

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On the basis of that advice, the Trust will file annual information returns, reporting to the Trust unitholders all items of income, gain, loss, deduction and credit. The Trust will allocate items of income, gain, loss, deductions and credits to Trust unitholders based on record ownership at each quarterly record date. It is possible that the IRS or another tax authority could disagree with this allocation method and could assert that income and deductions of the Trust should be determined and allocated on a daily, prorated or other basis, which could require adjustments to the tax returns of the Trust unitholders affected by the issue and result in an increase in the administrative expense of the Trust in subsequent periods.

Classification of the Net Profits Interest

Tax counsel to the Trust also advised the Trust at the time of formation that, for U.S. federal income tax purposes, based upon representations made by Whiting regarding the expected economic life of the underlying properties and the expected duration of the NPI, in its opinion the NPI should be treated as a “production payment” under Section 636 of the Code, or otherwise as a debt instrument. On the basis of that advice, the Trust treats the NPI as indebtedness subject to Treasury regulations applicable to contingent payment debt instruments, and by purchasing Trust units, a Trust unitholder agrees to be bound by the Trust’s application of those regulations, including the Trust’s determination of the rate at which interest will be deemed to accrue on the NPI. No assurance can be given that the IRS or another tax authority will not assert that the NPI should be treated differently. Any such different treatment could affect the timing and character of income, gain or loss in respect of an investment in Trust units and could require a Trust unitholder to accrue income at a rate different than that determined by the Trust.

Reporting Requirements for Widely-Held Fixed Investment Trusts

Some Trust units are held by middlemen, as such term is broadly defined in the Treasury regulations (and includes custodians, nominees, certain joint owners and brokers holding an interest for a custodian street name, collectively referred to herein as “middlemen”). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. The Bank of New York Mellon Trust Company, N.A., 919 Congress Avenue, Austin, Texas 78701, telephone number 512-236-6545, is the representative of the Trust that will provide the tax information in accordance with applicable Treasury regulations governing the information reporting requirements of the Trust as a WHFIT. Notwithstanding the foregoing, the middlemen holding Trust units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury regulations with respect to such Trust units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose Trust units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust units. 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.

Available Trust Tax Information

In compliance with the Treasury regulations reporting requirements for non-mortgage widely-held fixed investment trusts and the dissemination of Trust tax reporting information, the Trustee provides a generic tax information reporting booklet which is intended to be used only to assist Trust unitholders in the preparation of their 2013 federal and state income tax returns. The projected payment schedule for the NPI is included with the tax information booklet. This tax information booklet can be obtained at http://whitingwhz.investorhq.businesswire.com.

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6%, and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and also applicable to qualified dividends of individuals is 20%. The highest marginal U.S. federal income tax rate applicable to corporations is 35%, and such rate applies to both ordinary income and capital gains.

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Section 1411 of the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income generally will include a Trust unitholder’s allocable share of the Trust’s interest income plus the gain recognized from a sale of Trust units. In the case of an individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all investments, or (ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels depending on such individual’s federal income tax filing status. In the case of an estate or trust, the tax is imposed on the lesser of (x) undistributed net investment income, or (y) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Environmental Matters and Regulation

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 release, discharge or emission of materials into the environment; the handling of hazardous materials; or otherwise relating to environmental protection. These laws and regulations may, among other things:

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

• require the proper management and disposal of waste and 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 in sensitive areas, such as wilderness areas, wetlands, streams or areas that may contain endangered or threatened species and their habitats;

• require investigatory or remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits, plug and abandon wells and restore properties upon which wells are drilled;

• apply specific health and safety criteria addressing worker protection; and

• enjoin some or all of the operations of the 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 result in the assessment of significant 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 properties comprising 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 and disposal of hazardous and non-hazardous wastes. Under delegations of authority from the U.S. Environmental Protection Agency (“EPA”) the

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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. The EPA has not formally responded to this petition yet. 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 the hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. While Whiting generates materials in the course of its operations of the underlying properties that may be regulated as hazardous substances, Whiting has not been notified that it has been named as a potentially responsible party at or with respect to any Superfund sites. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, waste products or other chemicals into the environment.

The underlying properties of the Trust 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 of the Trust may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons and materials was not under Whiting’s control. These properties and the substances disposed or released on them may give rise to potential liabilities for Whiting pursuant 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 waters of the United States 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 waters of the United States 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.

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Hydraulic Fracturing.    Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight rock 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 to complete wells drilled on 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 recently issued guidance, which was published in the Federal Register on February 12, 2014, for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel.

At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities on drinking water resources. The EPA published a progress report of the study in December 2012 and expects to release a draft final report for public comment and peer review in 2014. Moreover, the EPA announced in October 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards for coalbed methane in 2013 and shale gas in 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, the U.S. Government Accountability Office and the White House Council for Environmental Quality. The U.S. Department of the Interior released a draft proposed rule in May 2012 governing hydraulic fracturing on federal and Indian oil and natural gas leases to require disclosure of information regarding the chemicals used in hydraulic fracturing, advance approval for well-stimulation activities, mechanical integrity testing of casing and monitoring of well-stimulation operations, and on May 24, 2013 the Federal Bureau of Land Management issued a revised draft of the proposed rule. On November 20, 2013, the U.S. House of Representatives passed the Protecting States’ Rights to Promote American Energy Security Act, which would ban the U.S. Department of the Interior from regulating hydraulic fracturing if enacted into law. In addition, legislation has been introduced in Congress from time to time 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 on activities 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 in Texas) 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, 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, local governments may seek to adopt, and some have adopted, ordinances within their jurisdictions restricting the use of or regulating the time, place and manner of drilling or hydraulic fracturing. 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, regulations or ordinances that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in states or local municipalities where the underlying properties are located, such legal requirements could make it more difficult or costly for Whiting to perform hydraulic fracturing activities on the underlying properties 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 and could reduce cash distributions by the Trust and the value of Trust units.

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 health and the environment because emissions of such gases are, according to the EPA, contributing to the

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warming of the earth’s atmosphere and other climate changes. Based on these findings, the EPA has adopted regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, as amended (the “CAA”), including one rule that limits emissions of GHGs from motor vehicles beginning with the 2012 model year. On June 3, 2010, the EPA also published regulations to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. On June 26, 2012, the U.S. Circuit Court for the District of Columbia upheld the EPA’s GHG regulations. Industry groups filed petitions for review of that decision with the U.S. Supreme Court and oral argument was scheduled for early 2014. In November 2010, the EPA published its final rule expanding its existing GHG monitoring and reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. These requirements became applicable in 2012 for emissions occurring in 2011, but industry groups have filed suit challenging certain provisions of the rules and are engaged in settlement negotiations to amend and correct the rules. Whiting believes that it is in compliance with all substantial applicable emissions requirements, and it is preparing to comply with future 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. The final cap-and-trade system began on January 1, 2012, and legally enforceable compliance obligations began with 2013 emissions. In the absence of new legislation, the EPA is issuing new regulations that limit emissions of GHGs associated with the operations of the underlying properties, which will require Whiting to incur costs to inventory and reduce emissions of GHGs associated with the operations of the underlying properties and that could adversely affect demand for the oil and natural gas produced. 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, floods and other climatic events.

Air Emissions.    The CAA 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, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. For example, in 2012, the EPA finalized rules establishing new air emission controls for oil and natural gas production operations. Specifically, the EPA’s rule includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. Among other things, these standards require the application of reduced emission completion techniques associated with the completion of newly drilled and fractured wells in addition to existing wells that are refractured. The rules also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. 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 cash distributions to unitholders. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA 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

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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 make a determination on listing more than 250 species as endangered or threatened under the ESA over the next several years. 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 (“OCSLA”) and the National Environmental Policy Act (“NEPA”) require federal agencies to evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions. OCSLA, 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, NEPA 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. This process has the potential to delay the development of oil and natural gas projects.

Whiting believes that it is in compliance in all material respects with all existing environmental laws and regulations applicable to the current operations of the underlying properties and that its continued compliance with existing requirements will not have a material adverse effect on the cash distributions to the Trust unitholders. For instance, Whiting did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2013 with respect to these properties. Additionally, Whiting has informed the Trust that Whiting is not aware of any environmental issues or claims that will require material capital expenditures during 2014 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.

Item 1A. Risk Factors

The market price for the Trust units may not reflect the value of the NPI held by the Trust and, in addition, over time will decline to zero shortly after the NPI termination date, which is currently estimated to be December 31, 2021.

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. Further, the market price of Trust units may be affected by factors other than the anticipated future Trust distributions. 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 NPI 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

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made to a unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the unitholder, and over time the market price of the Trust units will decline to zero shortly after the NPI termination date, which is currently estimated to be December 31, 2021.

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 through December 31, 2014.

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

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

• the actions of the Organization of Petroleum Exporting Countries;

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

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

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

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

• the level of global oil and natural gas inventories;

• developments of United States energy infrastructure, such as the approval (or lack thereof) to proceed with the Keystone XL pipeline from Hardesty, Alberta to Cushing, Oklahoma and the development of liquefied 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 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.

Whiting entered into hedge contracts, which are structured as costless collar arrangements that will hedge approximately 37% of the crude oil volumes expected to be produced from the underlying properties through December 31, 2014, based on the reserve report prepared by the Trust’s independent petroleum engineer dated as of December 31, 2013 (the “reserve report”). 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. Because of the differential between NYMEX or other benchmark prices of oil and natural gas and the wellhead price received, hedge contracts may not totally offset the effects of price fluctuations. Whiting has not entered into any hedge contracts relating to oil, natural gas or natural gas liquids expected to be produced after 2014, and the terms of the conveyance of the NPI prohibit Whiting from entering into any new hedging

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arrangements. As a result, the amounts of the cash distributions may fluctuate significantly after 2014 as a result of changes in commodity prices because there will be no hedge contracts in place to reduce the Trust’s exposure to oil and natural gas price volatility. The hedge contracts may also limit the amount of cash available for distribution if oil prices increase. In addition, the hedge contracts are subject to the risk of nonperformance of the counterparty and other risks. For a discussion of the hedge contracts, see “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of this Annual Report on Form 10-K.

Lower oil, natural gas and natural gas liquids prices 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 Trust unitholders.

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 NPI to replace the depleting assets and production.

The net proceeds payable to the Trust from the NPI are derived from the sale of oil, natural gas and natural gas liquids produced from the underlying properties and proceeds, if any, received by Whiting upon settlement of the hedge contracts. The reserves attributable to the underlying properties are depleting assets, which means that such reserves will decline over time. The underlying properties’ reserve report reflects that cumulative past production (on an 8/8ths gross basis) through December 31, 2013 represents an aggregate depletion percentage of 84.6% 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 continue to decline over time. As of December 31, 2013, the percentage of remaining reserves expected to be produced during the term of the NPI was 61.1%. The reserves attributable to the underlying properties declined 6.4% from December 31, 2012 to December 31, 2013. Based on the reserve report, overall production for both oil and gas attributable to the underlying properties is expected to decline at an average year-over-year rate of approximately 8.4% between 2014 and 2021, assuming the level of developmental drilling and investments on the underlying properties as assumed in the year-end reserve report. 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 NPI will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE has been produced from the underlying properties and sold (which amount is the equivalent of 10.61 MMBOE in respect to the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI).

Future maintenance projects on the underlying properties beyond those which are currently estimated may affect the quantity of proved reserves that can be economically produced from the underlying properties. The timing and size of these projects will depend on, among other factors, the market prices of oil, natural gas and natural gas liquids. If operators of the underlying properties do not implement required maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently

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expected by Whiting or estimated in the reserve report. Additionally, although Whiting retained a 10% interest in the net proceeds from the sale of oil, natural gas and natural gas liquids from the underlying properties, Whiting does not own any Trust units, which could reduce its economic incentive to operate the underlying properties in an efficient and cost-effective manner.

The Trust agreement provides that the Trust’s business activities are limited to owning the NPI and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyance related to the NPI. As a result, the Trust is not permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets or production attributable to the NPI, nor is the Trust 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 NPI may cease to produce in commercial quantities and the Trust may, therefore, cease to receive any distributions of net proceeds therefrom. Further, distributions will cease upon termination of the Trust.

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

The value of the Trust units and the amount of future cash distributions to the Trust unitholders depends upon, among other things, the accuracy of the production and reserves estimated to be attributable to the underlying properties and the NPI. 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 NPI and the “standardized measure” value attributable to the NPI are based on estimates of reserve quantities and revenues for the underlying properties. The quantities of reserves attributable to the underlying properties and the NPI 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 depends 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 reduces Trust distributions by reducing the amount of net proceeds available for distribution. For example, accidents may occur that result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any costs incurred in connection with any such accidents that are not insured against will have the effect of reducing the net proceeds available for distribution to the Trust. Also, Whiting does not have insurance policies in effect that

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are intended to provide coverage for losses solely related to hydraulic fracturing operations. Please read “— Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing.” above in these Risk Factors for a discussion of the uncertainty involved in the regulation of 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, for example, there have been recent accidents involving rail cars carrying crude oil, which resulted in the U.S. Department of Transportation (the “DOT”) issuing an emergency order on February 25, 2014 that requires rail shippers to test the makeup of such crude oil before transporting it. This move follows the safety alert the DOT issued in January 2014 that Bakken formation crude oil is more flammable than other types of crude oil. An accident involving rail cars could result in significant personal injuries and property and environmental damage. Additionally, added regulations in response to such accidents could result in additional costs that could reduce proceeds available for distribution.

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

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

The processes of drilling and completing wells are subject to numerous risks beyond the Trust’s and Whiting’s control, including risks that could delay the current drilling schedule of Whiting or any other operator of an underlying property and the risk that drilling will not result in commercially viable production. Neither Whiting nor any other operator is obligated to undertake any development activities, so any drilling and completion activities are subject to their 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;

• delays or limits on the issuance of drilling permits on federal leases, including as a result of government shutdowns;

• 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.

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The Trust and the Trust unitholders have no voting or managerial rights with respect to the underlying properties. As a result, neither the Trust nor the Trust unitholders 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, 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 58% of the underlying properties based on the standardized measure of discounted future net cash flows at December 31, 2013. However, for the 42% of the underlying properties that it does not operate, Whiting does not have control over normal operating procedures, expenditures or future development relating to such properties. The failure of an operator to adequately perform operations or an operator’s breach of the applicable agreements could reduce production from the underlying properties and the cash available for distribution to Trust unitholders. The success and timing of operational activities on properties operated by others therefore depends upon a number of factors outside of Whiting’s control, including the operator’s decisions with respect to the timing and amount of capital expenditures, the period of time over which the operator seeks to generate a return on capital expenditures, the inclusion of other participants in drilling wells, and the use of technology, as well as the operator’s expertise and financial resources and the operator’s relative interest in the underlying field. Operators may also opt to decrease operational activities following a significant decline in oil or natural gas 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 is 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.

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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 NPI relating to the abandoned well.

The amount of cash available for distribution by the Trust is 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 NPI bears 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 reduces the amount of cash received by the Trust and thereafter be 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 also reduces the amount of cash received by the Trust and thereafter be distributable to Trust unitholders. Accordingly, higher production and development costs and expenses related to the underlying properties directly decreases the amount of cash received by the Trust in respect of its NPI. In addition, cash available for distribution by the Trust is further reduced by the Trust’s general and administrative expenses.

If production and development costs on the underlying properties exceed the proceeds from 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 NPI, 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 prices 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 generally trades at a discount, but sometimes at a premium, to the relevant benchmark prices, such as NYMEX. 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 or premiums. Increases in the differential and 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 the Trust units.

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

The 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. The reserve report currently projects that 11.79 MMBOE will have been produced from the underlying properties and sold prior to 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 constant prices) because cash distributions attributable to such production will occur at a later date.

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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 NPI 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 production and development costs 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 NPI 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 NPI 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 NPI 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 NPI if the annual gross proceeds attributable to the NPI are less than $2.0 million for each of any two consecutive years. The sale of the NPI will result in the dissolution of the Trust. The net proceeds of any such sale will be distributed to the Trust unitholders.

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 amount 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). 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 NPI. Therefore, the market price of the Trust units will approach and eventually reach zero shortly after the end of the NPI term because cash distributions from the Trust will cease following the termination of such NPI, and the Trust will have no right to any additional production from the underlying properties after the term of the NPI.

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 NPI.

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• Whiting has the right, subject to significant limitations as described herein, to cause the Trust to release a portion of the NPI in connection with a sale of a portion of the oil and natural gas properties comprising the underlying properties to which such NPI relates. In such an event, the Trust is entitled to receive its proportionate share of the proceeds from the sale attributable to the NPI released.

• 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 are administered 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 NPI.

The Trust agreement permits the Trustee to sue Whiting on behalf of the Trust to enforce the terms of the conveyance creating the NPI. If the Trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of 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 are not 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 are 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 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.

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Strict, joint and several liability may be imposed under certain environmental laws and regulations, which could result in liability being imposed on Whiting with respect to its portion of the underlying properties due to the conduct of others or from Whiting’s actions even if such actions were in compliance with all applicable laws at the time those actions were taken. Private parties, including the surface estate owners of the real properties at which the underlying properties are located and the owners of facilities where petroleum hydrocarbons or wastes resulting from operations at the underlying properties are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damages. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If it were not possible to recover the resulting costs for such liabilities or non-compliance through insurance or increased revenues, then these costs could have a material adverse effect on the cash distributions to the Trust unitholders.

The Trust bears indirectly 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 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.

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 GHGs present an endangerment to public health 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 adopted regulations that restrict emissions of GHGs under existing provisions of the CAA, including one rule that limits emissions of GHGs from motor vehicles beginning with the 2012 model year. On June 3, 2010, the EPA also published regulations to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. On June 26, 2012, the U.S. Circuit Court for the District of Columbia upheld the EPA’s GHG regulations; a petition for review by the U.S. Supreme Court has not yet been filed and would be due in April 2013. In November 2010, the EPA published its final rule expanding its existing GHG monitoring and reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. These requirements became applicable in 2012 for emissions occurring in 2011, but industry groups have filed

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suit challenging certain provisions of the rules and are engaged in settlement negotiations to amend and correct the rules. 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. The final cap-and-trade system began on January 1, 2012, and legally enforceable compliance obligations began with 2013 emissions. In the absence of new legislation, the EPA is issuing new regulations that limit emissions of GHGs associated with the operations of the underlying properties which will require Whiting to incur costs to inventory and reduce emissions of GHGs associated with the operations of the underlying properties and that could adversely affect demand for the oil and natural gas produced. 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, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on the Trust’s assets and the amount of cash available for distribution to the Trust unitholders.

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

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 during the completion of wells drilled on the underlying properties, and Whiting expects it will also be used in the future. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA recently issued guidance, which was published in the Federal Register on February 12, 2014, for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel.

At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities on drinking water resources. The EPA published a progress report of the study in December 2012 and expects to release a draft of the report in late 2014 with a final peer reviewed report expected in 2016. Moreover, the EPA announced in October 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards for shale gas in 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, the U.S. Government Accountability Office and the White House Council for Environmental Quality. The U.S. Department of the Interior released a draft proposed rule in May 2012 governing hydraulic fracturing on federal and Indian oil and natural gas leases to require disclosure of information regarding the chemicals used in hydraulic fracturing, advance approval for well-stimulation activities, mechanical integrity testing of casing and monitoring of well-stimulation operations, and on May 24, 2013 the Federal Bureau of Land Management issued a revised draft of the proposed rule. On November 20, 2013, the U.S. House of Representatives passed the Protecting States’ Rights to Promote American Energy Security Act, which would ban the U.S. Department of the Interior from regulating hydraulic fracturing if enacted into law. In addition, legislation has been introduced in Congress from time to time 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 on activities relating to hydraulic fracturing in certain circumstances. For

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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 in Texas) 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, 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, local governments may seek to adopt, and some have adopted, ordinances within their jurisdictions restricting the use of or regulating the time, place and manner of drilling or hydraulic fracturing. 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, regulations or ordinances that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in the states or local municipalities where the underlying properties are located, such legal requirements could make it more difficult or costly for Whiting to perform hydraulic fracturing activities on the underlying properties 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 and could reduce cash distributions by the Trust and the value of Trust units.

The Trust’s NPI 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 NPI.

Whiting has recorded the conveyance of the NPI in the states where the underlying properties are located in the real property records in each county where these properties are located. The NPI 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 NPI 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 NPI 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 NPI in the pending bankruptcy proceeding.

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 58% of the underlying properties based on the standardized measure of discounted future net cash flows at December 31, 2013. 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.

Whiting has entered into hedge contracts, consisting of costless collar arrangements, with JPMorgan Chase Bank National Association 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

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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 “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of this Annual Report on Form 10-K.

Whiting’s ability to perform its obligations related to the operation of the underlying properties, its obligations to the counterparty related to the hedge contracts and its obligations to the Trust will depend on Whiting’s future financial condition and economic performance, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and upon financial, business and other factors, many of which are beyond the control of Whiting. Whiting cannot provide any assurance that its financial condition and economic performance will not deteriorate in the future. A substantial or extended decline in oil or natural gas prices may materially and adversely affect Whiting’s future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

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

In the event that the counterparty to the hedge contracts defaults on its obligations to make payments to Whiting under the hedge contracts, the cash distributions to the Trust unitholders could be materially reduced as the hedge payments are intended to provide additional cash to the Trust during periods of lower crude oil prices. In addition, because the hedge contracts are with a single counterparty, JPMorgan Chase Bank National Association, the risk of default is concentrated with one financial institution. Whiting cannot provide any assurance that this counterparty will not become a credit risk in the future. The hedge contracts also have default terms applicable to Whiting, including customary cross default provisions. If Whiting were to default, the counterparty to the hedge contracts could terminate the hedge contracts and the cash distributions to Trust unitholders could be materially reduced during periods of lower crude oil prices.

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

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.

Under certain circumstances, the Trust provides that the Trustee may be required to reconvey to Whiting a portion of the NPI, which may impact how quickly 11.79 MMBOE are produced from the underlying properties for purposes of the NPI.

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 NPI with respect to any such underlying property or well. The Trust will not receive any consideration for such reconveyance of a portion of the NPI. Such reconveyance of a portion of the NPI may extend the time it takes 11.79 MMBOE (10.61 MMBOE at the 90% NPI) to be produced from the underlying properties for purposes of the NPI.

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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 NPI 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 they anticipated.

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

If the NPI were not treated as a debt instrument, any deductions allowed to an individual Trust unitholder in their recovery of basis in the NPI 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.

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, and should consult their own tax advisors for advice regarding the state as well as federal tax implications of owning Trust units.

The Trust allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record ownership of the Trust units on the quarterly record date, instead of on the basis of the date a particular Trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the Trust unitholders.

The Trust generally allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record ownership of the Trust units on the quarterly record date, instead of on the basis of the date a particular Trust unit is transferred. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the Trust should be determined and allocated on a daily, prorated or other basis, which could require adjustments to the tax returns of the Trust unitholders affected by the issue and result in an increase in the administrative expense of the Trust in subsequent periods.

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

The U.S. federal income tax treatment of an investment in the Trust may be modified by administrative or legislative changes, or by judicial interpretation, at any time, possibly on a retroactive basis.

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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.

For income tax purposes, Trust unitholders are treated as if they own the Trust’s taxable asset (which for tax purposes, is a loan receivable owed to the Trust from Whiting) and they receive the Trust’s income and are directly taxable thereon as if no trust were in existence. The Trust unitholders generally do 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. Because the Trust typically generates taxable income that is 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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Description of 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 NPI 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 1,308 gross (388.5 net) producing oil and natural gas wells located in 48 predominately mature fields with established production profiles in 10 states. As of December 31, 2013, approximately 99.0% of estimated proved reserves attributable to the Trust were classified as proved developed producing reserves, 0.8% were classified as proved developed non-producing reserves and 0.2% were classified as proved undeveloped reserves. For the year ended December 31, 2013, the net production attributable to the underlying properties was 1,704 MBOE or 4,670 BOE/d. Whiting operates approximately 58% of the underlying properties based on the December 31, 2013 reserve report standardized measure of discounted future net cash flows.

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 and royalty interests retained by the owners of the land subject to the working interests. The royalty interests typically entitle the landowner to receive at least 12.5% of the revenue derived from oil and natural gas production 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 is a working interest owner’s percentage of production and revenues, after reducing such interest by the percentage of burdens on production such as royalties and overriding royalties.

The NPI entitles the Trust to receive 90% of the net proceeds from the sale of at least 11.79 MMBOE (10.61 MMBOE at the 90% NPI) of production from the underlying properties. As of December 31, 2013, on a cumulative accrual basis 3.18 MMBOE (30%) of the Trust’s total 10.61 MMBOE have been produced and sold, and the remaining minimum reserve balance of 7.42 MMBOE (at the 90% NPI) is expected to be produced prior to December 31, 2021 based on the Trust’s year-end 2013 reserve report. Since the Trust is not currently expected to contractually terminate until December 31, 2021 (also based on the year-end reserve report) additional reserves and production attributable to the NPI may be available for distribution to unitholders between the time that the Trust’s minimum 10.61 MMBOE have been produced and sold and the expected December 31, 2021 termination date of the Trust occurs. Accordingly, the Trust’s remaining reserves attributable

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to the 90% NPI are estimated to be 8.15 MMBOE as of December 31, 2013, although there is no assurance that this will occur. However, the reserve report is based on the assumptions included therein. See “Risk Factors” in Item 1A of this Annual Report on Form 10-K for additional discussion. The rate of future production cannot be predicted with certainty, and the Trust’s 10.61 MMBOE may be produced before or after the currently projected date. The proved reserves attributable to the underlying properties include all proved reserves expected to be economically produced during the remaining full 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 NPI.

Whiting’s retained interest in the underlying properties, after deducting the NPI, entitles it to 10% of the net proceeds from the sale of oil, natural gas and natural gas liquids production attributable to the underlying properties during the term of the NPI and all of the net proceeds thereafter. This interest retained by Whiting provides it with an incentive to operate (or cause to be operated) the underlying properties in an efficient and cost-effective manner. In addition, Whiting has agreed to operate the properties for which it is the designated operator as a reasonably prudent operator in the same manner that it would operate them if these properties were not burdened by the NPI. Furthermore, for those properties for which it is not the designated 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.

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 2014 through the estimated December 31, 2021 NPI termination date, assuming no additional developmental drilling or investments other than those assumed in the year-end reserve report. 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 future development is delayed, reduced, or cancelled.

Reserves

As of December 31, 2013, all of the Trust’s oil and gas reserves are attributable to properties within the United States. The following table summarizes estimated proved reserves (developed and undeveloped) and the standardized measure of discounted future net cash flows as of December 31, 2013 based on 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, 2013) attributable to i) the Trust based on the term of its NPI, and ii) the underlying properties on a full economic life basis (dollars in thousands):

	Whiting USA Trust II(2) (90% NPI through December 2021)						Underlying Properties (100% Full Economic Life)
	Oil(3) (MBbl)		Natural Gas (Mcf)		MBOE		Oil(3) (MBbl)		Natural Gas (Mcf)		MBOE
Proved reserves:
Developed		6,474		9,950		8,133		12,054		16,398		14,787
Undeveloped		16		—		16		24		—		24
Total proved — December 31, 2013		6,490		9,950		8,149		12,078		16,398		14,811
Standardized measure(1)					$	225,064					$	295,183

(1) Standardized measure of discounted future net cash flows as of December 31, 2013. No provision for federal or state income taxes has been provided because taxable income is passed through to the unitholders of the Trust. Therefore, the standardized measure of the Trust and of the underlying properties is equal to their corresponding pre-tax PV 10% values.

(2) The Trust’s estimated proved reserves as of December 31, 2013 on a 90% basis were 8,149 MBOE, which reserve amount includes only those quantities of proved reserves in the underlying properties that are available to satisfy the interests of Trust unitholders and does not include the remaining 10% of proved reserves in the underlying properties to which only Whiting would be entitled.

(3) Oil includes natural gas liquids.

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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. Oil and gas reserve quantities and related discounted future net cash flows have been derived from oil and gas prices calculated using an average of the first-day-of-the month price for each month within the most recent 12 months, pursuant to current SEC and FASB guidelines. Assumptions used to estimate reserve quantities and related discounted future net cash flows also include costs for estimated future production expenditures required to produce the proved reserves as of December 31, 2013. 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 underlying properties or to the NPI because future net revenues are not subject to taxation at the Trust level. See “Federal Income Tax Matters” in Item 1 of this Annual Report on Form 10-K for more information.

A rollforward of changes in net proved reserves attributable to the Trust from January 1, 2013 to December 31, 2013, and the calculation of the standardized measure of the related discounted future net revenues are contained in the Supplemental Oil And Gas Reserve Information (Unaudited) in the notes to the financial statements of the Trust included in this Annual Report on Form 10-K. Whiting has not filed reserve estimates covering the underlying properties with any other federal authority or agency.

In 2013, revisions to previous estimates increased proved reserves by a net amount of 201 MBOE. These revisions mainly consisted of i) increased estimates of future production associated with well workovers performed during 2013, and ii) higher crude oil and natural gas pricing incorporated into the Company’s reserve estimates at December 31, 2013 as compared to December 31, 2012.

Preparation of reserves estimates.    Whiting has advised the Trustee that 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, 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 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 (1992) 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 D. Ravnaas, President. Mr. Ravnaas is a State of Texas Licensed Professional Engineer. See Appendix 1 and Exhibit 99 of this Annual Report on Form 10-K 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 29 years of acquisition and reservoir engineering experience, holds a Bachelor’s degree in Petroleum Engineering from the Colorado School of Mines and is a member of the Society of Petroleum Engineers.

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As noted above, the current reserve report projects that 10.61 MMBOE attributable to the 90% NPI will be produced from the underlying properties prior to December 31, 2021. The exact rate of production attributable to the underlying properties cannot be accurately predicted as numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the estimates. 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 NPI.

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 number of fields and approximate acreage of these properties by region at December 31, 2013.

	Number  of Fields		Developed Acreage				Undeveloped Acreage				Total Acreage
Region			Gross		Net		Gross		Net		Gross		Net
Rocky Mountains		14		35,495		13,653		803		56		36,298		13,709
Permian Basin		17		34,299		25,076		2,000		942		36,299		26,018
Gulf Coast		8		11,257		4,381		470		153		11,727		4,534
Mid-Continent		9		3,294		1,849		80		72		3,374		1,921
Total		48		84,345		44,959		3,353		1,223		87,698		46,182

The following is a summary of the producing wells on the underlying properties as of December 31, 2013:

	Operated Wells				Non-Operated Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Oil		292		262.5		938		92.5		1,230		355.0
Natural gas		34		29.1		44		4.4		78		33.5
Total		326		291.6		982		96.9		1,308		388.5

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.

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Whiting did not drill any exploratory wells on the underlying properties during the periods presented. There were three wells that were in the process of being drilled as of December 31, 2013.

	Year Ended December 31,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Productive
Oil wells		8		0.43		4		0.05		20		4.71
Natural gas wells		—		—		—		—		2		0.06
Dry		—		—		—		—		—		—
Total		8		0.43		4		0.05		22		4.77

Oil and Natural Gas Production

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.

	Year Ended December 31,
	2013		2012		2011
Net sales volumes:
Oil production (MBbl)(1)		1,319		1,396		1,382
Natural gas production (MMcf)		2,312		2,636		2,717
Total production (MBOE)		1,704		1,836		1,834
Average daily production (MBOE/d)		4.7		5.0		5.0
Keystone South field sales volumes(2):
Oil production (MBbl)(1)		140		136		159
Natural gas production (MMcf)		574		664		596
Total production (MBOE)		236		247		258
Rangely field sales volumes(2):
Oil production (MBbl)(1)		184		182		187
Natural gas production (MMcf)		—		—		—
Total production (MBOE)		184		182		187
Average sales prices:
Oil (per Bbl)(1)	$	87.27	$	84.22	$	87.47
Natural gas (per Mcf)	$	4.84	$	4.57	$	6.22
Production costs per BOE(3)	$	25.73	$	22.55	$	19.41

(1) Oil includes natural gas liquids.

(2) The Rangley field was the only field that contained 15% or more of the total proved reserve volumes of the underlying properties as of December 31, 2013. There were no fields that contained 15% or more of the total proved reserve volumes of the underlying properties as of December 31, 2012. The Keystone South and Rangley fields were the only fields that contained 15% or more of the total proved reserve volumes of the underlying properties as of December 31, 2011.

(3) Production costs reported above exclude from lease operating expenses ad valorem taxes of $3.0 million ($1.74/BOE), $4.0 million ($2.17/BOE) and $3.8 million ($2.05/BOE) for the years ended December 31, 2013, 2012 and 2011, respectively.

Producing wells the Trust has an interest in or operates are part of eight enhanced oil recovery waterflood projects, which include both secondary (waterflood) and tertiary (CO2 injection) recovery efforts, and aggregate production from such enhanced oil recovery fields averaged 1,196 BOE/d during 2013 or 26% of 2013 daily production from the underlying properties. For these areas, Whiting needs to use enhanced recovery techniques in order to maintain oil and gas production from these fields.

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Delivery Commitments

Other than the underlying properties’ commitment of 11.79 MMBOE to the Trust pursuant to the terms of the NPI, 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.

Major Producing Areas

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 standardized measure of discounted future net cash flows at December 31, 2013, approximately 58% of these properties were operated by Whiting. Based on annual 2013 production attributable to the underlying properties, approximately 77% of production was crude oil and natural gas liquids and 23% of production was natural gas. These properties are located in mature fields and have established production profiles. However, production and distributions to the Trust will continue to decline over time.

Rocky Mountains Region.    The underlying properties in the Rocky Mountains region are located in Colorado, Wyoming, North Dakota and Montana. These properties consist of 14 fields of which Whiting operates wells in five of these fields. The Trust’s NPI does not include any of Whiting’s interests in the Bakken and Three Forks formations. The major fields in this region include the Rangely field that produces from the Weber Sand zone; the Garland field that produces from the Madison and Tensleep zones; the Cedar Hills field that produces from the Red River zone; and the Whiting-operated Torchlight field that produces from the Madison and Tensleep zones. For the year ended December 31, 2013, the net production attributable to the underlying properties in the region was 648.5 MBOE or 1.8 MBOE/d.

Permian Basin Region.    The Permian Basin region is one of the major hydrocarbon producing provinces in the continental United States. The underlying properties in the Permian Basin region are located in Texas and New Mexico. These properties consist of 17 fields, of which Whiting operates wells in 12 of these fields. The major fields in this region, include the Keystone South field that produces from the Clear Fork, Wichita Albany and Ellenberger zones; the Martin field that produces from the Clear Fork and Wichita Albany zones; the DEB field that produces from the Wolfcamp zone; the Signal Peak field that produces from the Wolfcamp zone; and the Sable field that produces from the San Andres zone. For the year ended December 31, 2013, the net production attributable to the underlying properties in the region was 781.3 MBOE or 2.1 MBOE/d.

Gulf Coast Region.    The underlying properties in the Gulf Coast region are located in Texas and Mississippi. These properties consist of eight onshore fields, and Whiting operates wells in four of these fields. The major field in this region is the Whiting-operated Lake Como field located in Mississippi that produces from the Smackover formation. For the year ended December 31, 2013, the net production attributable to the underlying properties in the region was 182.3 MBOE or 0.5 MBOE/d.

Mid-Continent Region.    The underlying properties in the Mid-Continent region are located in Michigan, Arkansas, Oklahoma and Texas. These properties consist of nine fields of which Whiting operates wells in five of these fields. The major field in this region is the Whiting-operated Wesson field located in Arkansas that produces from the Hogg Sand zone. For the year ended December 31, 2013, the net production attributable to the underlying properties in the region was 92.3 MBOE or 0.3 MBOE/d.

Abandonment and Sale of Underlying Properties

Any operator of the underlying properties, including Whiting, has 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

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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 NPI, 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, 2013, 2012 and 2011, there were 2, 2 and 11 gross wells, respectively, that were plugged and abandoned on the underlying properties, based on the determination that such wells were no longer economic to operate.

In addition, Whiting may, without the consent of the Trust unitholders, require the Trust to sell the NPI 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 NPI 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 NPI. Any net sales proceeds paid to the Trust are distributable to Trust unitholders for the quarter in which they are received. During 2013, Whiting had no divestitures of Trust properties.

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 NPI therein.

Whiting has informed the Trustee that Whiting believes 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 has informed the Trustee that Whiting believes that the existing burdens and obligations do not, in the aggregate, materially interfere with the use of the underlying properties and do not materially adversely affect the value of the NPI.

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At the time of its acquisitions of the underlying properties, Whiting undertook a title examination of these properties. As such, Whiting has informed the Trustee that Whiting believes its title to the underlying properties is, and the Trust’s title to the net profits interest is, 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.

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 NPI is a real or a personal property interest. Whiting has recorded the conveyance of the NPI in the relevant real property records of all applicable jurisdictions. Whiting has informed the Trustee that Whiting believes the delivery and recording of the conveyance creates a fully conveyed and vested property interest under the applicable state’s laws, but because there is no direct authority to this effect in some jurisdictions, this may not always be the result. Whiting has also informed the Trustee that Whiting believes that it is possible the NPI may not be treated as a real property interest under the laws of certain of the jurisdictions where the underlying properties are located. Whiting has also informed the Trustee that Whiting believes that, if, during the term of the NPI, Whiting becomes involved as a debtor in a bankruptcy proceeding, the NPI 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 NPI 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 NPI in the pending bankruptcy proceeding. Although no assurance can be given, Whiting has informed the Trustee that Whiting believes that the conveyance of the NPI 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.

Item 3. Legal Proceedings

Currently, there are not any legal proceedings pending to which the Trust is a party or of which any of its property is the subject.

Item 4. Mine Safety Disclosures

Not applicable.

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P A R T    II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

The Trust units commenced trading on the New York Stock Exchange on March 23, 2012 under the symbol “WHZ.” Prior to March 23, 2012, there was no established public trading market for the Trust units. The high and low sales prices per unit for each quarter in 2013 and 2012 were as follows:

	For the Year Ended December 31, 2013
	High		Low
First quarter (January 1 through March 31)	$	17.63	$	14.27
Second quarter (April 1 through June 30)	$	14.64	$	12.67
Third quarter (July 1 through September 30)	$	14.06	$	12.49
Fourth quarter (October 1 through December 31)	$	14.48	$	12.51

	For the Year Ended December 31, 2012
	High		Low
First quarter (March 23 through March 31)	$	24.64	$	21.00
Second quarter (April 1 through June 30)	$	23.96	$	17.62
Third quarter (July 1 through September 30)	$	21.86	$	18.50
Fourth quarter (October 1 through December 31)	$	20.10	$	14.36

At December 31, 2013, the 18,400,000 units outstanding were held by two unitholders of record.

Distributions

Each quarter, the Trustee determines 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 NPI 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 are reduced by any cash the Trustee decides to hold as a reserve against future liabilities. Quarterly cash distributions during the term of the Trust are 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. The table below presents the net cash proceeds for each quarter of 2013 and 2012 attributable to the 90% NPI, the estimated Trust expenses, Montana state income taxes reserved for by the Trustee and the resulting distributable income per Trust unit.

2013 Quarterly Distributions	Net Cash Proceeds (90% NPI)		Estimated Trust Expenses		Montana State Income Tax Withholdings		Distributable Income per Unit
First quarter	$	12,180,733	$	200,000	$	5,665	$	0.650819
Second quarter		11,936,618		300,000		9,646		0.631901
Third quarter		13,814,090		200,000		9,832		0.739362
Fourth quarter		16,553,937		200,000		10,079		0.888253
Total	$	54,485,378	$	900,000	$	35,222	$	2.910335

2012 Quarterly Distributions	Net Cash Proceeds (90% NPI)		Estimated Trust Expenses		Montana State Income Tax Withholdings		Distributable Income per Unit
Second quarter	$	18,078,189	$	500,000	$	14,398	$	0.954554
Third quarter		16,594,046		125,000		13,444		0.894326
Fourth quarter		14,350,918		350,000		5,513		0.760620
Total	$	49,023,153	$	975,000	$	33,355	$	2.609500

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Subsequent to year end, on March 3, 2014, a distribution of $0.651431 per Trust unit was paid to Trust unitholders owning Trust units as of February 19, 2014. This aggregate distribution to all Trust unitholders consisted of net cash proceeds of $12.2 million paid by Whiting to the Trust, less a provision of $200,000 for estimated Trust expenses and $4,744 for Montana state income tax withholdings. There were no realized gains or losses on hedge settlements during the fourth quarterly payment period of 2013.

Equity Compensation Plans

The Trust does not have any employees and, therefore, does not maintain any equity compensation plans.

Recent Sales of Unregistered Securities

None.

Purchases of Equity Securities

There were no purchases of Trust units by the Trust or any affiliated purchaser during the fourth quarter of 2013.

Item 6. Selected Financial Data

The Trust was formed on December 5, 2011. The conveyance of the NPI, however, did not occur until March 28, 2012. As a result, the Trust did not recognize any income or make any distributions during 2011 or during the first quarter of 2012. The following table sets forth selected data for the Trust for the years ended December 31, 2013 and 2012 and as of December 31, 2013, 2012 and 2011 based on the Trust’s audited financial statements:

	Year Ended December 31,
	2013		2012
Income from net profits interest	$	54,485,378	$	49,023,153
Distributable income	$	53,550,156	$	48,014,798
Distributable income per unit	$	2.910335	$	2.609500

	December 31,
	2013		2012		2011
Trust corpus	$	144,990,141	$	171,354,819	$	10
Total assets at year-end	$	145,211,292	$	171,515,701	$	10
Trust units outstanding		18,400,000		18,400,000		—

Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operation

This document contains forward-looking statements, which give our current expectations or forecasts of future events. Please refer to “Forward-Looking Statements” which follows the Table of Contents of this Form 10-K for an explanation of these types of statements.

Overview and Trust Termination

The Trust was formed on December 5, 2011. The conveyance of the NPI, however, did not occur until March 28, 2012. As a result, the Trust did not recognize any income or make any distributions during 2011 or during the first quarter of 2012. The NPI was conveyed effective for production from the underlying properties starting from January 1, 2012. Therefore, the Trust’s first quarterly distribution paid on May 30, 2012 consisted of an amount in cash paid by Whiting for net proceeds generated from the underlying properties since the January 1, 2012 effective date through March 31, 2012.

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The Trust does not conduct any operations or activities. The Trust’s purpose is, in general, to hold the NPI, to distribute to unitholders cash that the Trust receives in respect of the NPI, and to perform certain administrative functions in respect of the NPI and the Trust units. The Trust derives substantially all of its income and cash flows from the NPI, which is in turn subject to commodity hedge contracts through December 31, 2014. The NPI entitles the Trust to receive 90% of the net proceeds from the sale of production from the underlying properties.

Oil and gas prices historically have been volatile and may fluctuate widely in the future. The table below highlights these price trends by listing quarterly average NYMEX crude oil and natural gas prices for the periods indicated through December 31, 2013. The 2013 NPI distributions are mainly affected, however, by October 2012 through September 2013 oil prices and September 2012 through August 2013 natural gas prices.

	2011								2012								2013
	Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4
Crude oil (per Bbl)	$	94.25	$	102.55	$	89.81	$	94.02	$	102.94	$	93.51	$	92.19	$	88.20	$	94.34	$	94.23	$	105.82	$	97.50
Natural gas (per MMBtu).	$	4.10	$	4.32	$	4.20	$	3.54	$	2.72	$	2.21	$	2.81	$	3.41	$	3.34	$	4.10	$	3.58	$	3.60

Lower oil and gas prices on production from the underlying properties could cause the following: (i) a reduction in the amount of net proceeds to which the Trust is entitled; and (ii) a reduction in the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties causing an extension of the length of time required to produce 11.79 MMBOE (10.61 MMBOE at the 90% NPI). Alternatively, higher oil and natural gas prices may potentially result in the following: (i) an increase in the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties, and (ii) cash settlement losses on commodity derivatives.

Trust termination.    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 (10.61 MMBOE at the 90% NPI), and the Trust will soon thereafter wind up its affairs and terminate, after which it will pay no further distributions. 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 or yield. As a result, the market price of the Trust units will decline to zero at termination of the Trust. As of December 31, 2013, on a cumulative accrual basis, 3.18 MMBOE (30%) of the Trust’s total 10.61 MMBOE have been produced and sold (of which proceeds from the sale of 384 MBOE, which is 90% of 427 MBOE, were distributed to the unitholders in the Trust’s February 2014 distribution). The remaining reserve quantities are projected to be produced prior to December 31, 2021, based on the Trust’s reserve report as of December 31, 2013. Since the Trust is not currently expected to contractually terminate until December 31, 2021, additional reserves and production attributable to the NPI may be available for distribution to unitholders (also based on the year-end reserve report) between the time that the Trust’s minimum 10.61 MMBOE have been produced and sold and the expected December 31, 2021 termination date of the Trust occurs, although there is no assurance that this will occur. For additional discussion relating to and of the assumptions underlying the estimated date when 11.79 MMBOE (10.61 MMBOE at the 90% NPI) will be produced and sold from the underlying properties, after which the Trust will soon thereafter wind up its affairs and terminate, see “Description of the Underlying Properties” in Item 2 of this Annual Report on Form 10-K.

For a discussion of material changes to proved reserves, see “Reserves” in Item 2 of this Annual Report on Form 10-K. Additionally, for a discussion of the need to use enhanced recovery techniques, see “Oil and Natural Gas Production” in Item 2 of this Annual Report on Form 10-K.

Capital Expenditure Activities

The primary goal of the planned capital expenditures relative to the underlying properties is to mitigate a portion of the natural decline in production from producing properties. The underlying properties have a capital expenditure budget per the reserve report of $31.5 million estimated to be spent over eight years. No assurance

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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 limited control over the timing and amount of capital expenditures relative to such fields. Please read “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.” 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 attributable to the 90% NPI) (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	2014 – 2021 Planned Capital Expenditures (in millions)		Gross Wells		Net Wells
Rocky Mountains
Rangely — CO2 and maintenance capital	$	18.6		—		—
Rangely — drill wells		0.6		5		0.2
Garland — maintenance capital		11.3		—		—
Rocky Mountains Total	$	30.5		5		0.2
Permian Basin
Keystone South — recompletions	$	1.0		1		1.0
Permian Basin Total	$	1.0		1		1.0
Total	$	31.5		6		1.2

Rocky Mountains Region.    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 capital is also expended for the drilling of additional wells to optimize field recovery. According to information provided by the operator, the 2014 estimated capital expenditures are $2.9 million allocated to the underlying properties’ interest and are comprised of development drilling activities, plant and equipment expenditures and CO₂ purchases. These capital expenditures scheduled for 2014 include the drilling of four development wells and one injector well. After 2014, Whiting estimates that this level of drilling and facility expenditures as well as CO₂ purchases will continue through 2021 and will total approximately $16.3 million as allocated to the underlying properties’ interest. 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 in the Rocky Mountains region at this time, further study or offsetting drilling activity may result in capital expenditures in the future.

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Whiting owns a non-operated working interest in the Garland field located in Big Horn County, Wyoming, which produces from the Madison and Tensleep zones. According to information provided by the operator, the estimated capital expenditures allocated to the underlying properties’ interest are $1.4 million per year through 2021 related to plant and equipment expenditures. Although Whiting is not aware of any other development plans by this operator or other operators of the underlying properties in this region, these operators may propose capital expenditures in the future.

Permian Basin Region.    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 one well from the currently completed zone to another zone expected to be productive in the wellbore. This recompletion is scheduled to be performed in 2014 when the currently producing zones reach their economic limit. The capital expenditures necessary to perform this recompletion are estimated at approximately $1.0 million allocated to the underlying properties’ interest. 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 additional capital expenditures in the future. Additionally, although Whiting is not aware of any other development plans by other operators of the underlying properties in the Permian Basin, these operators may propose capital expenditures in the future.

Although Whiting has not identified any future capital expenditures for its operated fields in the Gulf Coast and Mid-Continent regions 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 these regions, operators may propose capital expenditures in the future.

Results of Trust Operations

Results of the Trust for the Year Ended December 31, 2013 Compared to the Pro Forma Results of the Trust for the Year Ended December 31, 2012

Presented below is a summary of the Trust’s income from net profits interest and distributable income for the year ended December 31, 2013, consisting of the February 2013 distribution, May 2013 distribution, August 2013 distribution and November 2013 distribution received by the Trust. In addition, because the Trust had not engaged in any activities during the three months ended March 31, 2012 other than organizational activities, pro forma income from net profit interest and distributable income for the Trust for the year ended December 31, 2012 has been presented, so that investors can review comparative results of operations for the Trust for the 2013 and 2012 periods. The Trust’s pro forma results of operations for the year ended December 31, 2012 have been presented on a modified cash basis of accounting in the table below. This basis of presentation is consistent with the Trust’s financial statements, which have also been prepared on a modified cash basis as described in Note 2 to the Trust’s Financial Statements included in this Annual Report on Form 10-K.

The pro forma income from net profits interest, distributable income, and related financial data presented below assume (i) that the conveyance of the NPI in the underlying properties occurred on December 5, 2011, and (ii) that the NPI was effective for oil and gas production from the underlying properties beginning in 2011. The pro forma financial information below has been derived from the unaudited pro forma financial statement, as included in Note 9 to the Trust’s financial statements included in this Annual Report on Form 10-K. The Trust believes that the assumptions used to prepare this pro forma data provide a reasonable basis for presenting the effects directly attributable to these transactions. However, the pro forma amounts set forth in the table below are for informational purposes only and do not purport to present the results that would have actually occurred had

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the Trust formation and net profits interest conveyance been completed on December 5, 2011 as indicated above, nor are they indicative of future results of operations.

Trust Results
	Year Ended December 31, 2013			Pro Forma Year  Ended December  31, 2012(e)
Sales volumes:
Oil from underlying properties (Bbl)(a)		1,299,274	(c)		1,353,169	(f)
Natural gas from underlying properties (Mcf)		2,374,890	(c)		2,683,616	(f)
Total production (BOE)		1,695,089			1,800,438
Average sales prices:
Oil (per Bbl)(a)	$	84.94		$	86.32
Natural gas (per Mcf)	$	4.73	(d)	$	5.03	(d)
Costs (per BOE):
Lease operating expenses	$	25.98		$	23.29
Production taxes	$	3.69		$	3.93
Revenues:
Oil sales(a)	$	110,357,643	(c)	$	116,808,893	(f)
Natural gas sales		11,235,608	(c)		13,493,055	(f)
Total revenues	$	121,593,251		$	130,301,948
Costs:
Lease operating expenses	$	44,036,270		$	41,929,928
Production taxes		6,254,301			7,082,755
Development Costs		10,763,371			6,877,032
Cash settlement (gains) losses on commodity derivatives(b)		—			—
Total costs	$	61,053,942		$	55,889,715
Net proceeds	$	60,539,309		$	74,412,233
Net profits percentage		90	%		90	%
Income from net profits interest	$	54,485,378		$	66,971,010
Provision for estimated Trust expenses		900,000			1,068,750	(g)
Montana state income tax withheld		35,222			59,585	(h)
Distributable income	$	53,550,156		$	65,842,675

(a) Oil includes natural gas liquids.

(b) As discussed in “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of this Annual Report on Form 10-K, all costless collar hedge contracts terminate as of December 31, 2014. Consequently, for all distributions after the February 2015 distribution, there will be no further cash settlement gains or losses on commodity hedges, and the Trust will have increased exposure to oil and natural gas price volatility.

(c) Oil and gas sales volumes and related revenues for the year ended December 31, 2013 (consisting of Whiting’s February 2013 distribution, May 2013 distribution, August 2013 distribution and November 2013 distribution to the Trust) generally represent crude oil production from October 2012 through September 2013 and natural gas production from September 2012 through August 2013.

(d) The average sales price of natural gas for the gas production months within the distribution period exceeded the average NYMEX gas prices for those same months within the period due to the “liquids rich” content of a portion of the natural gas volumes produced by the underlying properties.

(e) Pro forma sales volumes, average sales prices, costs and revenue data have been derived from the historical accounting records of the underlying properties. Such amounts 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.

(f) Pro forma oil and gas sales volumes and related revenues for the year ended December 31, 2012 (consisting of Whiting’s pro forma February 2012 distribution, May 2012 distribution, August 2012 distribution and November 2012 distribution to the Trust) generally

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represent crude oil production from October 2011 through September 2012 and natural gas production from September 2011 through August 2012.

(g) For the year ended December 31, 2012, actual expenses from the May 2012 distribution, August 2012 distribution and November 2012 distribution were $975,000 and the pro forma provision for estimated Trust expenses for the pro forma February 2012 distribution were assumed to be $93,750.

(h) Pro forma Montana state income tax withheld assumes that 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.

Income from Net Profits Interest.    Income from net profits interest is recorded on a cash basis when NPI proceeds are received by the Trust from Whiting. NPI proceeds that Whiting remits to the Trust are based on the oil and gas production Whiting has received payment for within one month following the end of the most recent fiscal quarter. Whiting receives payment for its crude oil sales generally within 30 days following the month in which it is produced, and Whiting receives payment for its natural gas sales generally within 60 days following the month in which it is produced. Income from net profits interest is generally a function of oil and gas revenues, lease operating expenses, production taxes and development costs as follows:

Revenues.    The 2013 actual oil and natural gas revenues were $8.7 million (or 7%) lower as compared to 2012 pro forma oil and gas revenues. Sales revenue is a function of average commodity prices realized and oil and gas volumes sold. The decrease in revenue between periods was due to lower sales prices realized for oil and natural gas and lower oil and natural gas production volumes during 2013 as compared to the 2012 pro forma period. The average sales price realized declined for crude oil by 2% and for natural gas by 6% between periods. Additionally, oil volumes declined by 53,895 Bbl (or 4%) and gas volumes declined by 308,726 Mcf (or 12%) when comparing 2013 actual production to 2012 pro forma production volumes. Based on the December 31, 2013 reserve report, overall production attributable to the underlying properties is expected to decline at an average year-over-year rate of approximately 8.4% from 2014 through the estimated December 31, 2021 NPI termination date. Oil sales volumes decreased period over period primarily due to normal field production decline and a shut-in well, which was off-line during the first quarter of 2013 and during portions of the second quarter of 2013. This well returned to normal production during the third and fourth quarters of 2013. These oil volume decreases were partially offset, however, by three workover wells that came online during the last twelve months and by differences in timing associated with revenues distributed and received from non-operated parties. Gas sales volume decreases were primarily related to i) normal field production decline, and ii) two gas wells that were shut-in for a portion of the year ended December 31, 2013. One of these shut-in wells resumed consistent production again during the third and fourth quarters of 2013. These gas volume decreases were partially offset by differences in timing associated with revenues distributed and received from non-operated properties.

Lease Operating Expenses.    Lease operating expenses (“LOE”) in 2013 increased $2.1 million (or 5%) as compared to the 2012 pro forma period primarily due to a $1.9 million increase in ad valorem taxes paid during 2013 as compared to pro forma 2012. This increase in LOE coupled with the decrease in overall production volumes between periods resulted in higher LOE of 12% on a per BOE basis, from $23.29 during the pro forma year ended December 31, 2012 to $25.98 for the same period in 2013.

Production Taxes.    Production taxes are typically calculated as a percentage of oil and gas revenues, and production taxes as a percent of revenues remained relatively consistent for the year ended December 31, 2013 and pro forma 2012 at 5.1% and 5.4%, respectively. Overall production taxes in 2013, however, decreased $0.8 million (or 12%) as compared to the 2012 pro forma amounts, primarily due to lower oil and natural gas sales revenue between periods.

Development Costs.    Actual development costs in 2013 were $3.9 million (or 57%) higher as compared to 2012 pro forma development costs. This increase was primarily due to $1.4 million in capital expenditures incurred at the Rangely Weber field in connection with new drilling and facility expansions being carried out at this project. Also contributing to higher development costs between periods was an increase in capital expenditures at the Keystone South field of $2.0 million related to four well recompletions.

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Provision for Estimated Trust Expenses.    The provision for estimated Trust expenses in 2013 decreased $0.2 million (or 16%) as compared to the 2012 pro forma period primarily due to i) initial start-up legal fees and other administrative costs chargeable to the Trust during the pro forma 2012 period, and ii) a decrease in cash reserves withheld for future Trust expenses of $0.1 million in 2013.

Distributable Income.    For the year ended December 31, 2013, the Trust’s actual distributable income was $53.6 million and was based on income from net profits interest of $54.5 million, which was reduced by a provision for estimated Trust expenses of $900,000 and Montana state income tax withholdings of $35,222. This compares to pro forma distributable income for 2012 of $65.8 million that was based on pro forma income from net profits interest of $67.0 million, which has been reduced by $1,068,750 for estimated Trust expenses and $59,585 in Montana state income tax withholdings.

Results of the Trust for the Year Ended December 31, 2012 Compared to the Pro Forma Results of the Trust for the Year Ended December 31, 2011

Presented below is a summary of the Trust’s income from net profits interest and distributable income for the year ended December 31, 2012, consisting of the May 2012 distribution, August 2012 distribution and November 2012 distribution received by the Trust. In addition, because the Trust had not engaged in any activities during 2011 other than organizational activities, pro forma income from net profit interest and distributable income for the Trust for the year ended December 31, 2011 has been presented, so that investors can review comparative results of operations for the Trust for the 2012 and 2011 periods. The Trust’s pro forma results of operations for the year ended December 31, 2011 have been presented on a modified cash basis of accounting in the table below, and this basis of presentation is consistent with the Trust’s financial statements, which have also been prepared on a modified cash basis as described in Note 2 to the Trust’s Financial Statements included in this Annual Report on Form 10-K.

The pro forma income from net profits interest, distributable income, and related financial data presented below give effect to the Trust formation and the conveyance of the NPI in the underlying properties to the Trust by Whiting, as if they occurred on January 1, 2011. Accordingly, the 2011 pro forma results include four complete quarterly NPI distributions from Whiting to the Trust (the pro forma February, May, August and November 2011 distributions), whereas the 2012 actual results only include three quarterly distributions (consisting of the Trust’s actual May 2012 distribution, August 2012 distribution and November 2012 distribution). The pro forma financial information below has been derived from the unaudited pro forma financial statements, as included in the prospectus dated March 22, 2012 for the initial public offering of the Trust’s units. The Trust believes that the assumptions used to prepare this pro forma data provide a reasonable basis for presenting the effects directly attributable to these transactions. However, the pro forma amounts set forth in the table below are for informational purposes only and do not purport to present the results that would have actually

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occurred had the Trust formation and net profits interest conveyance been completed on January 1, 2011 or for the period presented or which may be realized in the future.

Trust Results
	Year Ended December 31, 2012			Pro Forma Year  Ended December  31, 2011(e)(f)
Sales volumes:
Oil from underlying properties (Bbl)(a)		1,004,848	(c)		1,409,056	(g)
Natural gas from underlying properties (Mcf)		1,796,628	(c)		2,885,493	(g)
Total production (BOE)		1,304,286			1,889,972
Average sales prices:
Oil (per Bbl)(a)	$	85.67		$	83.96
Natural gas (per Mcf)	$	4.55	(d)	$	5.94
Costs (per BOE):
Lease operating expenses	$	23.48		$	20.31
Production taxes	$	3.85		$	3.80
Revenues:
Oil sales(a)	$	86,089,470	(c)	$	118,302,940	(g)
Natural gas sales		8,177,660	(c)		17,138,142	(g)
Total revenues	$	94,267,130		$	135,441,082
Costs:
Lease operating expenses	$	30,624,146		$	38,376,358
Production taxes		5,017,008			7,176,627
Development Costs		4,155,806			17,292,910
Cash settlement (gains) losses on commodity derivatives(b)		—			—
Total costs	$	39,796,960		$	62,845,895
Net proceeds	$	54,470,170		$	72,595,187
Net profits percentage		90	%		90	%
Income from net profits interest	$	49,023,153		$	65,335,668
Provision for estimated Trust expenses		975,000			375,000	(h)
Montana state income tax withheld		33,355			94,454	(i)
Distributable income	$	48,014,798		$	64,866,214

(a) Oil includes natural gas liquids.

(b) As discussed in “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of this Annual Report on Form 10-K, all costless collar hedge contracts terminate as of December 31, 2014. Consequently, for all distributions after the February 2015 distribution, there will be no further cash settlement gains or losses on commodity hedges, and the Trust will have increased exposure to oil and natural gas price volatility.

(c) Oil and gas sales volumes and related revenues for the year ended December 31, 2012 (consisting of Whiting’s May 2012 distribution, August 2012 distribution and November 2012 distribution to the Trust) generally represent crude oil production from January 2012 through September 2012 and natural gas production from January 2012 through August 2012.

(d) The average sales price of natural gas for the gas production months within the distribution period exceeded the average NYMEX gas prices for those same months within the period due to the “liquids rich” content of a portion of the natural gas volumes produced by the underlying properties.

(e) Pro forma amounts set forth below for the 2011 period give effect to the Trust formation and the conveyance of the NPI in the underlying properties to the Trust by Whiting, as if these transactions occurred on January 1, 2011.

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(f) Pro forma sales volumes, average sales prices, costs and revenue data have been derived from the historical accounting records of the underlying properties. Such amounts 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.

(g) Oil and gas sales volumes and related revenues for the pro forma year ended December 31, 2011 (consisting of Whiting’s pro forma February, May, August and November 2011 NPI distributions to the Trust) generally represent crude oil production from October 2010 through September 2011 and natural gas production from September 2010 through August 2011.

(h) Pro forma provision for estimated Trust expenses assumes an administrative fee paid to Whiting of $200,000 and an annual administrative fee paid to the Trustee of $175,000. Going forward, the Trust’s aggregate general and administrative costs will encompass legal fees, accounting fees, engineering fees, printing costs and other expenses properly chargeable to the Trust, which have been estimated to be approximately $625,000. If these estimated general and administrative expenses were included in the 2011 pro forma results, the distributable income would have been $64,241,214 for the pro forma year ended December 31, 2011. Due to the omission of general and administrative expenses other than the $375,000 administrative fee from the 2011 pro forma results, this pro forma financial statement may not be indicative of the results to be realized going forward.

(i) Pro forma Montana state income tax withheld assumes that 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.

Income from Net Profits Interest.    Income from net profits interest is recorded on a cash basis when NPI proceeds are received by the Trust from Whiting. NPI proceeds that Whiting remits to the Trust are based on the oil and gas production Whiting has received payment for within one month following the end of the most recent fiscal quarter. Whiting receives payment for its crude oil sales generally within 30 days following the month in which it is produced, and Whiting receives payment for its natural gas sales generally within 60 days following the month in which it is produced. Income from net profits interest is generally a function of oil and gas revenues, lease operating expenses, production taxes and development costs as follows:

Revenues.    Actual 2012 oil and natural gas revenues were $41.2 million (or 30%) lower as compared to 2011 pro forma oil and gas revenues. Sales revenue is a function of oil and gas volumes sold and average commodity prices realized. Gas volumes declined by 1,088,865 Mcf (or 38%) and oil volumes declined by 404,208 Bbl (or 29%) when comparing 2012 actual production to 2011 pro forma production volumes. Both of these volume decreases between periods are principally due to the actual 2012 results including only three quarterly NPI distributions from Whiting to the Trust (the May, August, and November 2012 distributions), whereas the pro forma 2011 results included four complete quarterly periods of NPI distributions to the Trust.

Also contributing to the 30% decrease in actual 2012 oil and gas revenues as compared to the 2011 pro forma revenues was a decline in the average sales price realized for natural gas of 23% between periods. Partially offsetting the above production-related and gas price-related decreases in net revenues, however, was an increase in the average sales price realized for crude oil of 2% between the 2012 actual and 2011 pro forma periods.

Lease Operating Expenses.    Lease operating expenses (“LOE”) in 2012 decreased $7.8 million (or 20%) as compared to 2011 pro forma LOE amounts. This decrease in LOE between periods was due to the 2012 actual results including only three quarterly NPI distributions from Whiting to the Trust (the May, August, and November 2012 distributions), whereas the pro forma 2011 results included four complete quarterly periods of NPI distributions to the Trust. Despite the overall decrease in LOE between periods, LOE on a per BOE basis was 16% higher in 2012 compared to pro forma 2011 results. LOE per BOE amounted to $23.48 for 2012, which was up from $20.31 per BOE for the 2011 pro forma period. This increase on a per BOE basis was mainly due to $2.3 million in higher costs of oil field goods and services, a $0.7 million increase in labor and overhead costs on Whiting-operated properties, and $0.7 million in higher electricity costs between periods.

Production Taxes.    Production taxes are typically calculated as a percentage of oil and gas revenues, and production taxes as a percentage of revenues remained constant at 5.3% between the 2012 actual and 2011 pro forma periods. Overall production taxes in 2012, however, decreased $2.2 million (or 30%) as compared to the 2011 pro forma amounts. This decrease between periods is due to the 2012 actual results including only three quarterly NPI distributions from Whiting to the Trust (the May, August, and November 2012

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distributions), whereas the pro forma 2011 results included four complete quarterly periods of NPI distributions to the Trust.

Development Costs. Actual development costs in 2012 were $13.1 million (or 76%) lower as compared to 2011 pro forma development costs. This decrease was primarily driven by the Keystone South field’s capital expenditures declining by $8.2 million between periods as a result of significant drilling projects that were carried out on this field during 2011 and which did not continue into 2012. Also contributing to the 76% decline in development costs between periods was a reduction in capital projects at the North Vacuum and Rangely Weber fields, which resulted in development cost decreases of $2.2 million and $1.2 million, respectively, from 2011 to 2012.

Provision for Estimated Trust Expenses.    The provision for estimated Trust expenses in 2012 was $600,000 higher than this same provision included in the 2011 pro forma results. This increase was mainly due to the Trust’s aggregate general and administrative (“G&A”) costs in 2012 encompassing legal fees, accounting fees, engineering fees, printing costs, the annual administrative fee paid to Whiting and the Trustee, and other admin costs properly chargeable to the Trust, whereas the 2011 pro forma provision for Trust expenses only included the annual administrative fee paid to Whiting of $200,000 and the annual administrative fee paid to the Trustee of $175,000. Partially offsetting this increase attributable to all G&A costs of the Trust being included in the 2012 results, was a decrease of $93,750 due to the provision for estimated Trust expenses in 2012 including only $281,250 related to administrative fees paid to Whiting and the Trustee, while this same provision in the 2011 pro forma results included $375,000 relating to these fees.

Distributable Income.    For the year ended December 31, 2012, the Trust’s actual distributable income was $48.0 million and was based on income from net profits interest of $49.0 million, which was reduced by a provision for estimated Trust expenses of $975,000 and Montana state income tax withholdings of $33,355. This compares to pro forma distributable income for 2011 of $64.9 million that was based on pro forma income from net profits interest of $65.3 million, which has been reduced by $375,000 for estimated Trust expenses and $94,454 in Montana state income tax withholdings. Actual 2012 distributable income is lower than pro forma 2011 distributable income because actual 2012 results include three quarterly NPI distributions from Whiting to the Trust, whereas the pro forma 2011 results include four complete quarterly periods of NPI distributions to the Trust.

Liquidity and Capital Resources

The Trust has no source of liquidity or capital resources other than cash flows from the NPI. Other than Trust administrative expenses, including any reserves established by the Trustee for future liabilities, the Trust’s only use of cash is for distributions to Trust unitholders. Administrative expenses include payments to the Trustee and the Delaware Trustee, a quarterly fee to Whiting pursuant to an administrative services agreement, and expenses in connection with the discharge of the Trustee’s duties, including third party engineering, audit, accounting and legal fees. Each quarter, the Trustee determines the amount of funds available for distribution to unitholders. Available funds are the excess cash, if any, received by the Trust from the NPI and other sources (such as interest earned on any amounts reserved by the Trustee) that quarter, over the Trust’s expenses for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities. The Trustee may borrow funds required to pay liabilities if the Trustee determines that the cash on hand and the cash to be received are insufficient to cover the Trust’s liabilities. If the Trustee borrows funds, the Trust unitholders will not receive distributions until the borrowed funds are repaid.

Income to the Trust from the NPI is based on the calculation and definitions of “gross proceeds” and “net proceeds” contained in the conveyance agreement, which is filed as an exhibit to this report, and reference is hereby made to such conveyance agreement for the actual definitions of “gross proceeds” and “net proceeds”.

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Whiting may reserve from the gross proceeds amounts up to a total of $2.0 million at any time for future development, maintenance or operating expenses. However, Whiting has not funded such a reserve since the inception of the Trust, including during the years ended December 31, 2013 and 2012. Instead, Whiting deducted from the gross proceeds only actual costs paid for development, maintenance and operating expenses.

Plugging and abandonment costs related to the underlying properties, net of any proceeds received from the salvage of equipment, cannot be included as a deduction in the calculation of net proceeds pursuant to the terms of the conveyance agreement. During the year ended December 31, 2013, Whiting incurred $1.2 million of plugging and abandonment charges on the underlying properties that were not passed on to the unitholders of the Trust.

In June 2012, Whiting established a $1.0 million letter of credit for Trustee in order to provide it with a mechanism to pay the operating expenses of the Trust, in the event that Whiting should fail to lend funds to the Trust if requested to do so by the Trustee. This letter of credit will not be used to fund NPI distributions to unitholders, and Whiting has no obligation to lend funds to the Trust. If the Trustee were to draw on the letter of credit or borrow funds from Whiting or otherwise, no further distributions would be made to unitholders until all such amounts have been repaid by the Trust.

The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust’s liquidity or the availability of capital resources.

Off-Balance Sheet Arrangements

The Trust has no off-balance sheet arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations other than the conveyed commodity hedge contracts disclosed in the section “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of this Annual Report on Form 10-K.

Contractual Obligations

The following table summarizes the Trust’s obligations and commitments as of December 31, 2013 to make future payments during the specified time periods:

	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years(d)
Delaware Trustee fees(a)	$	28,000	$	3,500	$	7,000	$	7,000	$	10,500
Trustee administrative service fees(b)		1,467,854		175,000		350,000		363,234		579,620
Whiting administrative service fees(c)		1,600,000		200,000		400,000		400,000		600,000
Total	$	3,095,854	$	378,500	$	757,000	$	770,234	$	1,190,120

(a) Pursuant to the terms of the Trust agreement, the Trust is obligated to pay the Delaware Trustee a fee of $3,500 per year.

(b) Pursuant to the terms of the Trust agreement, the Trust is obligated to pay the Trustee an administrative fee of $175,000 per year, which escalates annually by 2.5% starting in 2017.

(c) Pursuant to the terms of the administrative services agreement with Whiting, the Trust is obligated throughout the term of the Trust to pay Whiting an administrative services fee of $50,000 per quarter for accounting, engineering, legal and other professional services performed by Whiting on behalf of the Trust. The administrative services agreement will expire upon the termination of the NPI unless terminated early by mutual agreement of the Trustee and Whiting.

(d) The “more than 5 years” period represents obligations through the December 2021 estimated Trust termination date, based on the Trust’s 2013 reserve report, although actual amounts paid may differ from these estimates.

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New Accounting Pronouncements

There were no accounting pronouncements issued during the year ended December 31, 2013 applicable to the Trust or its financial statements.

Critical Accounting Policies and Estimates

The financial statements of the Trust are significantly affected by its basis of accounting and estimates related to its oil and gas properties and proved reserves, as summarized below.

Basis of Accounting.    The Trust’s financial statements are prepared on a modified cash basis, which is a comprehensive basis of accounting other than GAAP. This method of accounting is consistent with reporting of taxable income to the Trust unitholders. The most significant differences between the Trust’s financial statements and those prepared in accordance with GAAP are:

a) Income from net profits interest is recognized when NPI distributions are received by the Trust rather than accrued in the month of production that they are earned;

b) Distributions to Trust unitholders are recorded when paid by the Trust rather than accrued when owed;

c) Trust general and administrative expenses (which include the Trustee’s fees as well as administrative, accounting, engineering, legal, and other professional fees) are recorded when paid by the Trust rather than when incurred; and

d) Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under GAAP.

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 for the Trust and its results 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,Extractive Activities – Oil and Gas:Financial Statements of Royalty Trusts. For additional information regarding the Trust’s basis of accounting, see Note 2 to the Financial Statements included in this Annual Report on Form 10-K.

All amounts included in the Trust’s financial statements are based on cash amounts received or disbursed, or on the carrying value of the net profits interests, which was derived from the historical cost of the interests at the date of their transfer from Whiting less accumulated amortization to date. Accordingly, there are no fair value estimates included in the Trust’s financial statements.

Oil and Gas Reserves.    The proved oil and gas reserves for the underlying properties are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices and production costs, may justify revision of such estimates. Accordingly, oil and gas quantities ultimately recovered and the timing of production may be substantially different from estimates, and we are unable to predict changes in reserve quantity estimates as such quantities are dependent on future economic and operational conditions.

The standardized measure of discounted future net cash flows is prepared using assumptions made pursuant to FASB and SEC guidelines. Such assumptions include using average fiscal-year oil and gas prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month reporting period) and year-end costs for estimated future production expenditures. Discounted future net cash

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flows are calculated using a 10% discount rate. Changes in any of these assumptions could have a significant impact on the standardized measure. The standardized measure does not necessarily result in an estimate of the current fair market value of proved reserves.

Amortization of Net Profits Interest.    We amortize the investment in net profits interest using the units-of-production method. Our rate of recording amortization is dependent upon our estimates of total proved reserves, which incorporates various assumptions and future projections. If the estimates of total proved reserves decline significantly, the rate at which we record amortization expense would increase, reducing Trust corpus.

Impairment of Investment in Net Profits Interest.    We review the value of our investment in net profits interest whenever the Trustee judges that events and circumstances indicate that the recorded carrying value of the investment in net profits interest may not be recoverable. Potential impairments of the investment in net profits interest are determined by comparing future net undiscounted cash flows to the net book value at the end of each period. If the net capitalized cost exceeds undiscounted future cash flows, the cost of the investment in net profits interest is written down to “fair value,” which is determined using net discounted future cash flows from the net profits interest. Different pricing assumptions or discount rates could result in a different calculated impairment.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Hedge Contracts

The primary asset of and source of income to the Trust is the term NPI, which generally entitles the Trust to receive 90% of the net proceeds from oil and gas production from the underlying properties. Consequently, the Trust is exposed to market risk from fluctuations in oil and gas prices. Through 2014, however, the NPI is subject to commodity hedge contracts in the form of costless collars entered into by Whiting, which are intended to reduce, but not eliminate, the NPI’s exposure to crude oil price volatility. No additional hedges are allowed to be placed on Trust assets, and the Trust cannot therefore enter into derivative contracts for speculative or trading purposes.

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 liquid production from the underlying properties under floating market price contracts each month. Whiting has entered into certain hedge contracts through December 31, 2014 to manage the exposure to crude oil price volatility associated with revenues generated from the underlying properties, and to achieve more predictable cash flows. However, these contracts also limit the amount of cash available for distribution if prices increase above the fixed ceilings of the hedges. The hedge contracts consist of costless collar arrangements placed with a single trading counterparty, JPMorgan Chase Bank National Association. Whiting cannot provide assurance that this trading counterparty will not become a credit risk in the future.

Crude oil costless collar arrangements settle based on the average of the closing 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 hedge counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price.

In connection with Whiting’s conveyance on March 28, 2012 of the term NPI to the Trust, the rights to any future hedge payments Whiting makes or receives on certain of its derivative contracts (representing 493 MBbl of crude oil from January 2014 through December 2014) were also been conveyed to the Trust. As a result, such

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hedge payments will be included in the Trust’s calculation of net proceeds, and Trust unitholders thereby receive 90% of the future economic results of such hedges.

The table below summarizes all of the outstanding costless collars that Whiting entered into and then in turn conveyed, as described in the preceding paragraph, to the Trust (of which Trust unitholders receive 90% of the future economic results). This quantity of hedged oil volumes represents approximately 37% of the underlying properties’ oil production from January through December 2014, based on the estimated production of proved reserves as projected in the Trust’s December 31, 2013 reserve report.

	Crude Oil Collars
	Volumes (Bbl)		Price (per Bbl) Floor /Ceiling
Three months ending March 31, 2014		127,500	$	80.00/$122.50
Three months ending June 30, 2014		124,500	$	80.00/$122.50
Three months ending September 30, 2014		121,800	$	80.00/$122.50
Three months ending December 31, 2014		119,100	$	80.00/$122.50

The collared hedges shown above have the effect of providing a protective floor while allowing Trust unitholders to share in upward price movements up to the ceiling. Consequently, while these hedges are designed to decrease exposure to price decreases, they also have the effect of limiting the benefit of price increases beyond the ceiling. For the crude oil contracts listed above, a hypothetical $10.00 change in the NYMEX price above the ceiling price or below the floor price applied to the notional amounts would cause an aggregate change in the cash settlement (gains) losses on all oil commodity derivatives of $4.9 million to Whiting, of which 90% would be transferred to the Trust. These hypothetical cash settlement (gains) losses would be recognized as contracts expire in future periods through 2014.

The amounts received by Whiting from the counterparty upon settlements of these hedge contracts will reduce the production and development costs related to the underlying properties when calculating the net proceeds. However, if the hedge payments received by Whiting under the hedge contracts and other non-production revenue exceed production and development costs during a quarterly period, the ability to use such excess amounts to offset such costs may be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period where the hedge payments and the other non-production revenue are less than such 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.

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Item 8. Financial Statements and Supplementary Data

The following financial statements are set forth under “Financial Statements and Supplementary Data” in Item 8 of this Annual Report on Form 10-K on the pages indicated:

Index to Whiting USA Trust II Financial Statements

Financial Statements — as of December 31, 2013 and 2012 and for the Years ended December 31, 2013 and 2012 and the Period from December 5, 2011 (inception) through December 31, 2011
Report of Independent Registered Public Accounting Firm	59
Statements of Assets, Liabilities and Trust Corpus — Modified Cash Basis	60
Statements of Distributable Income — Modified Cash Basis	60
Statements of Changes in Trust Corpus — Modified Cash Basis	60
Notes to Modified Cash Basis Financial Statements	61
Underlying Properties of Whiting Petroleum Corporation Statements of Historical Revenues and Direct Operating Expenses — for the Years ended December 31, 2011 and 2010
Report of Independent Registered Public Accounting Firm	71
Statements of Historical Revenues and Direct Operating Expenses	72
Notes to Statements of Historical Revenues and Direct Operating Expenses	73

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Trustee and Unit Holders of

Whiting USA Trust II

c/o The Bank of New York Mellon Trust Company, N.A., Trustee

Austin, Texas

We have audited the accompanying statements of assets, liabilities and trust corpus — modified cash basis of Whiting USA Trust II (the “Trust”) as of December 31, 2013 and 2012, the related statements of distributable income and changes in trust corpus—modified cash basis for the years ended December 31, 2013 and 2012 and the statement of changes in trust corpus – modified cash basis for the period from December 5, 2011 (date of inception) through December 31, 2011. These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note 2 to the financial statements these statements were prepared on the 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, such financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of Whiting USA Trust II as of December 31, 2013 and 2012, and its distributable income and changes in trust corpus for the years ended December 31, 2013 and 2012 and its changes in trust corpus for the period from December 5, 2011 (date of inception) through December 31, 2011, on the comprehensive basis of accounting described in Note 2 to the financial statements.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Trust’s internal control over financial reporting as of December 31, 2013, based on the criteria established inInternal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 13, 2014 expressed an unqualified opinion on the Trust’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Austin, Texas

March 13, 2014

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WHITING USA TRUST II

Statements of Assets, Liabilities and Trust Corpus

	December 31,
	2013			2012
ASSETS
Cash and short-term investments	$	221,161		$	160,892
Investment in net profits interest, net		144,990,131			171,354,809
Total assets	$	145,211,292		$	171,515,701
LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses	$	221,151		$	160,882
Trust corpus (18,400,000 Trust units issued and outstanding at December 31, 2013 and 2012)		144,990,141			171,354,819
Total liabilities and Trust corpus	$	145,211,292		$	171,515,701
Statements of Distributable Income
	Year Ended December 31,
	2013			2012
Income from net profits interest	$	54,485,378		$	49,023,153
General and administrative expenses		(839,731	)		(814,118	)
Cash reserves (withheld) used for current Trust expenses		(60,269	)		(160,882	)
State income tax withholding		(35,222	)		(33,355	)
Distributable income	$	53,550,156		$	48,014,798
Distributable income per unit	$	2.910335		$	2.609500

Statements of Changes in Trust Corpus
	Year Ended December 31, 2013			Year Ended December 31, 2012			Period from December 5, 2011(inception) through December 31, 2011
Trust corpus, beginning of period	$	171,354,819		$	10		$	—
Investment in net profits interest		—			194,032,491			10
Distributable income		53,550,156			48,014,798			—
Distributions to unitholders		(53,550,156	)		(48,014,798	)		—
Amortization of investment in net profits interest		(26,364,678	)		(22,677,682	)		—
Trust corpus, end of period	$	144,990,141		$	171,354,819		$	10

The accompanying notes are an integral part of these modified cash basis financial statements.

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WHITING USA TRUST II

NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS

1. ORGANIZATION OF THE TRUST

Formation 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, as Delaware Trustee (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, a 100%-owned subsidiary of Whiting, to the Trust. The term NPI is an interest in certain of Whiting Oil and Gas’ properties located in the Rocky Mountains, Permian Basin, Gulf Coast and Mid-Continent regions (the “underlying properties”). The NPI is the only asset of the Trust, other than cash reserves held for future Trust expenses. As of December 31, 2013, these oil and gas properties included interests in approximately 1,308 gross (388.5 net) producing oil and gas wells.

The NPI is passive in nature, and the Trustee has no management control over and no responsibility relating to the operation 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 amount 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, after which it will pay no further distributions. As of December 31, 2013 on a cumulative accrual basis, 3.18 MMBOE (30%) of the Trust’s total 10.61 MMBOE have been produced and sold, and the remaining reserve quantities of 7.42 MMBOE (at the 90% NPI) are projected to be produced prior to December 31, 2021, based on the Trust’s reserve report as of December 31, 2013. Since the Trust is not currently expected to contractually terminate until December 31, 2021, additional reserves and production attributable to the NPI may be available for distribution to unitholders (also based on the year-end reserve report) between the time that the Trust’s minimum 10.61 MMBOE have been produced and sold and the expected December 31, 2021 termination date of the Trust occurs. Accordingly, the Trust’s remaining reserves attributable to the 90% NPI are estimated to be 8.15 MMBOE as of December 31, 2013.

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 that 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, which may be a non-interest bearing account, and make other short term investments with the funds distributed to the Trust.

Initial Issuance of Trust Units and Net Profits Interest Conveyance — On March 21, 2012, the registration statement on Form S-1/S-3 (Registration No. 333-178586) filed by Whiting and the Trust in connection with the initial public offering of the Trust’s units was declared effective by the SEC. On March 28, 2012, the Trust issued 18,400,000 Trust units to Whiting in exchange for the conveyance of the term NPI from Whiting Oil and Gas, which is described above. Immediately thereafter, Whiting completed an initial public offering of units of beneficial interest in the Trust, selling 18,400,000 Trust units to the public at $20.00 per unit.

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WHITING USA TRUST II

NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS — (Continued)

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. Actual cash distributions to the Trust are 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 paid by the Trust;

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

d) Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under GAAP;

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

f) The Trust evaluates impairment of the investment in net profits interest by comparing the undiscounted cash flows expected to be realized from the investment in net profits interest to the NPI carrying value. If the expected future undiscounted cash flows are less than the carrying value, the Trust recognizes an impairment loss for the difference between the carrying value and the estimated fair value of the investment in net profits interest. 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 or oil and natural gas production conditions deteriorate, write-downs could be required in the future.

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 for the Trust’s activities and results 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,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 are received or expenses are 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.

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WHITING USA TRUST II

NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS — (Continued)

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.

Concentration of Credit Risk — The underlying properties from which the NPI is derived 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 by purchaser that accounted for 10% or more of the underlying properties’ total oil and gas sales for the years ended December 31, 2013 and 2012:

	2013		2012
Chevron USA		15%		14%
Plains Marketing, LP		14%		16%
Phillips 66 Company		12%		8%
Marathon Oil Corporation		11%		11%

There is significant competition among purchasers of crude oil and natural gas and if Whiting were to lose any of its largest purchasers of oil and gas from the underlying properties, several entities could reasonably be expected to purchase crude oil and natural gas produced from the underlying properties with little or no interruption to their sales.

The underlying properties’ oil and gas revenues, which are included in the NPI net proceeds computation, are subject to commodity hedge contracts through December 31, 2014. The hedge contracts consist of costless collar arrangements that are placed with a single trading counterparty, JPMorgan Chase Bank National Association, and there is no assurance that this trading counterparty will not become a credit risk in the future.

Use of Estimates — The preparation of financial statements requires estimates and assumptions that affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Significant estimates affecting these financial statements include estimates of proved oil and gas reserves, which are used to compute the Trust’s amortization of its investment in net profits interest and its impairment assessments. Although the Trustee believes that these estimates are reasonable, actual results could differ from those estimates.

Recent Accounting Pronouncements — There were no accounting pronouncements issued during the year ended December 31, 2013 applicable to the Trust or its financial statements.

3. INVESTMENT IN NET PROFITS INTEREST

Whiting Oil and Gas conveyed the NPI to the Trust in exchange for 18,400,000 Trust units. The investment in net profits interest was recorded at the historical cost basis of Whiting on March 28, 2012, the date of conveyance (except for the derivatives which are reflected at their fair value as of March 31, 2012), and was calculated as follows:

	Year Ended December 31, 2012
Oil and gas properties	$	368,785,829
Accumulated depletion		(174,625,538	)
Oil and gas properties, net		194,160,291
Derivative liability		(127,800	)
Net predecessor cost of net profits interest conveyed to the Trust	$	194,032,491

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WHITING USA TRUST II

NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS — (Continued)

As of December 31, 2013, accumulated amortization of the investment in net profits interest was $49.0 million.

4. INCOME FROM NET PROFITS INTEREST

The Trust received income from net profits interest as follows:

	Year Ended December 31,
	2013			2012
Revenues:
Oil sales(a)	$	110,357,643	(c)	$	86,089,470	(d)
Natural gas sales		11,235,608	(c)		8,177,660	(d)
Total revenues		121,593,251			94,267,130
Costs:
Lease operating expenses		44,036,270			30,624,146
Production taxes		6,254,301			5,017,008
Development costs		10,763,371			4,155,806
Cash settlement gains received on commodity derivatives(b)		—			—
Total costs		61,053,942			39,796,960
Net proceeds		60,539,309			54,470,170
Net profits percentage		90	%		90	%
Income from net profits interest	$	54,485,378		$	49,023,153

(a) Oil includes natural gas liquids.

(b) There were no realized gains or losses on hedge settlements during the years ended December 31, 2013 or 2012. All costless collar hedge contracts terminate as of December 31, 2014. Consequently, for all distributions after the February 2015 distribution, there will be no further cash settlement gains or losses on commodity hedges, and the Trust will have increased exposure to oil and natural gas price volatility.

(c) Oil and gas sales volumes and related revenues for the year ended December 31, 2013 (consisting of Whiting’s February 2013 distribution, May 2013 distribution, August 2013 distribution and November 2013 distribution to the Trust) generally represent crude oil production from October 2012 through September 2013 and natural gas production from September 2012 through August 2013.

(d) Oil and gas sales volumes and related revenues for the year ended December 31, 2012 (consisting of Whiting’s May 2012 distribution, August 2012 distribution and November 2012 distribution to the Trust) generally represent crude oil production from January 2012 through September 2012 and natural gas production from January 2012 through August 2012.

5. INCOME TAXES

The Trust is a grantor trust and therefore is not subject to federal income taxes. Accordingly, no recognition has been given to federal income taxes in the Trust’s financial statements or in the Trust’s standardized measure of discounted future net cash flows. The Trust unitholders are treated as the owners of Trust income and corpus, and the entire taxable income of the Trust is 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. Whiting withheld $35,222 and $33,355 related to Montana state income taxes for the years ended December 31, 2013 and 2012, respectively. For Arkansas, Colorado, Michigan, Mississippi, New Mexico, North Dakota and Oklahoma, neither the Trust nor Whiting is withholding the income tax due such states on distributions made to an

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WHITING USA TRUST II

NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS — (Continued)

individual resident or nonresident Trust unitholder, as long as the Trust is taxed as a grantor trust under the Internal Revenue Code.

6. DISTRIBUTION TO UNITHOLDERS

Actual cash distributions to the Trust unitholders 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 are made by the Trustee no later than 60 days following the end of each quarter (or the next succeeding business day) to the Trust unitholders of record on the 50th day following the end of each quarter. Such amounts 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 any adjustments for changes made by the Trustee during such quarter in any cash reserves established for future expenses of the Trust.

7. RELATED PARTY TRANSACTIONS

Plugging and Abandonment —During the years ended December 31, 2013 and 2012, Whiting incurred $1.2 million and $1.0 million, respectively, of plugging and abandonment costs on the underlying properties. Pursuant to the terms of the conveyance agreement, plugging and abandonment charges relating to the underlying properties, net of any proceeds received from the salvage of equipment, are funded entirely by Whiting and are not therefore included as a deduction in the calculation of net proceeds or otherwise deducted from Trust unitholders over the term of the Trust.

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 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. The following table presents the Trust’s portion of these overhead charges for the distributions made during the years ended December 31, 2013 and 2012:

	Year Ended December 31,
	2013		2012
Total overhead charges	$	1,687,077	$	1,306,663
Overhead charge per month per active operated well	$	431	$	400

Administrative Services Fee —Under the terms of the administrative services agreement, the Trust is obligated to pay a quarterly administration fee of $50,000 to Whiting 60 days following the end of each calendar quarter. General and administrative expenses in the Trust’s statements of distributable income for the years ended December 31, 2013 and 2012 includes $200,000 and $150,000, respectively, for quarterly administrative fees paid to Whiting.

Trustee Administrative Fee —Under the terms of the Trust agreement, the Trust pays an annual administrative fee to the Trustee of $175,000, which is paid in four quarterly installments of $43,750 each and is billed in arrears. Starting in 2017, such fee escalates by 2.5% each year. General and administrative expenses in the Trust’s statements of distributable income for the years ended December 31, 2013 and 2012 includes $175,000 and $131,250, respectively, for administrative fees paid to the Trustee.

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WHITING USA TRUST II

NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS — (Continued)

Letter of Credit — In June 2012, Whiting established a $1.0 million letter of credit for the Trustee in order to provide it with a mechanism to pay the operating expenses of the Trust, in the event that Whiting should fail to lend funds to the Trust if requested to do so by the Trustee. This letter of credit will not be used to fund NPI distributions to unitholders, and Whiting has no obligation to lend funds to the Trust. If the Trustee were to draw on the letter of credit or borrow funds from Whiting or otherwise, no further distributions would be made to unitholders until all such amount have been repaid by the Trust.

8. SUBSEQUENT EVENTS

On March 3, 2014, a distribution of $0.651431 per Trust unit was paid to Trust unitholders owning Trust units as of February 19, 2014. This aggregate distribution to all Trust unitholders consisted of net cash proceeds of $12.2 million paid by Whiting to the Trust, less a provision of $200,000 for estimated Trust expenses and $4,744 for Montana state income tax withholdings. There were no realized gains or losses on hedge settlements during the fourth quarterly payment period of 2013.

9. PRO FORMA FINANCIAL STATEMENTS (UNAUDITED)

The following unaudited pro forma statements of distributable income assume that the conveyance of the term NPI occurred on December 5, 2011, the Trust’s formation date, 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 and do not purport to present the results that would have actually occurred had the NPI conveyance been completed on the assumed date or for the periods presented or which may be realized in the future.

To produce the pro forma financial information, management made certain estimates and assumptions. These estimates are based on the most recently available information. To the extent there are significant changes in these amounts, the assumptions and estimates herein could change significantly. The unaudited pro forma statement of distributable income should be read in conjunction with the “Trustee’s Discussion and Analysis of Financial Condition and Results of Operation” included in this Form 10-K and the historical financial statements of the Trust, including the related notes, included in this Form 10-K.

WHITING USA TRUST II

Unaudited Pro Forma Statements of Distributable Income

	Year Ended December 31, 2012			December 5 (inception)  to December 31, 2011(a)
Historical Results
Distributable income, as reported	$	48,014,798		$	—
Pro Forma Adjustments
Income from net profits interest		17,947,857	(b)		—	(a)
Less:
Trust general and administrative expenses		(93,750	)(c)		—	(c)
State income tax withholding		(26,230	)(d)		—
Distributable income	$	65,842,675		$	—
Distributable income per unit	$	3.578406		$	—

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WHITING USA TRUST II

NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS — (Continued)

(a) The Trust uses the modified cash basis of accounting, and revenues are therefore recorded when received. The pro forma statement of distributable income for the period ended December 31, 2011 assumes that the conveyance of the term NPI occurred on December 5, 2011 (the inception date of the Trust) and that the NPI was effective for oil and gas production from the underlying properties beginning in 2011, but because the initial distribution from Whiting to the Trust is not due until 60 days following the first quarterly period for which the NPI is effective (which these statements assume is the fourth quarter of 2011), there would be no pro forma income from net profits interest received by the Trust on a cash basis and therefore recognized during the period from December 5 to December 31, 2011.

(b) The Trust uses the modified cash basis of accounting, and revenues are therefore recorded when received. The pro forma statements of distributable income assume (i) that the conveyance of the term NPI occurred on December 5, 2011 (the inception date of the Trust), and (ii) that the NPI was effective for oil and gas production from the underlying properties beginning in 2011. Because quarterly cash distributions to the Trust are made by Whiting no later than 60 days following the end of each quarter, this adjustment assumes that the first quarterly NPI distribution to the Trust during 2012 would have occurred by February 29, 2012 (covering net cash proceeds received by Whiting for oil sales from October 1, 2011 through December 31, 2011 and gas sales from September 1, 2011 through November 30, 2011).

Furthermore, this adjustment assumes that the second quarterly NPI distribution to the Trust (occurring in May of 2012) would have been a complete distribution, thereby covering net cash proceeds for oil sales from January 1, 2012 through March 31, 2012 and gas sales from December 1, 2011 through February 29, 2012. Since the Trust’s historical distributable income already includes net cash proceeds received by Whiting for oil sales from January 1, 2012 through March 31, 2012 and gas sales for January and February of 2012, this amount therefore incrementally adjusts the Trust’s historical results for the May 2012 distribution in order to include net proceeds attributable to natural gas sales for December of 2011.

(c) The Trust is obligated to pay a quarterly administrative fee to Whiting of $50,000 60 days following the end of each quarter and an annual administrative fee to the Trustee of $175,000, which is paid in four quarterly installments of $43,750 each and is billed in arrears. Neither Whiting’s nor the Trustee’s administrative fees would have been paid in 2011 given the assumptions underlying these pro forma statements. The Trust’s historical distributable income for the year ended December 31, 2012 already includes three payments of $50,000 for Whiting’s quarterly administrative fee and $131,250 for three quarterly installments of the Trustee’s annual administrative fee.

(d) 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 is 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.

10. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

Estimates of proved reserves attributable to the Trust and the related valuations were based on reports prepared by the Trust’s independent petroleum engineers Cawley, Gillespie & Associates, Inc. Proved reserve estimates included herein conform to the definitions prescribed by the FASB and SEC. 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.

As of December 31, 2013, all of the underlying properties’ oil and gas reserves are attributable to properties within the United States. Proved reserves attributable to the Trust and related standardized measure valuations are prepared on an accrual basis for all periods presented, which is the basis on which Whiting and the underlying properties maintain their production records and is different from the cash basis on which the Trust production records are computed.

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WHITING USA TRUST II

NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS — (Continued)

The following is a summary of the changes in quantities of proved oil and gas reserves attributable to the Trust for the year ended December 31, 2013:

	Oil (MBbl)			Natural Gas (MMcf)			MBOE
Balance — January 1, 2012(1)		8,278			13,982			10,608
Revisions to previous estimates		458			274			503
Extensions and discoveries		4			3			5
Divestitures		—			—			—
Production		(1,257	)		(2,372	)		(1,652	)
Balance — December 31, 2012(1)		7,483			11,887			9,464
Revisions to previous estimates		178			140			201
Extensions and discoveries		17			4			18
Divestitures		—			—			—
Production		(1,187	)		(2,081	)		(1,534	)
Balance — December 31, 2013(1)		6,491			9,950			8,149
Proved developed reserves:
January 1, 2012		8,175			13,812			10,477
December 31, 2012		7,446			11,848			9,421
December 31, 2013		6,475			9,950			8,133
Proved undeveloped reserves:
January 1, 2012		103			170			131
December 31, 2012		37			39			43
December 31, 2013		16			—			16

(1) Reserves related to the underlying properties on a 100% full economic life basis as of January 1, 2012, December 31, 2012 and December 31, 2013 were 18.3 MMBOE, 15.8 MMBOE and 14.8 MMBOE, respectively. The oil and gas reserve quantities presented in the tables above are on a 90% NPI Trust life basis.

Notable changes in proved reserves for the year ended December 31, 2013 included:

• Revisions to previous estimates.    In 2013, revisions to previous estimates increased proved reserves by a net amount of 201 MBOE. These revisions mainly consisted of i) increased estimates of future production associated with well workovers performed during 2013, and ii) higher crude oil and natural gas pricing incorporated into the Company’s reserve estimates at December 31, 2013 as compared to December 31, 2012.

Notable changes in proved reserves for the year ended December 31, 2012 included:

• Revisions to previous estimates.    In 2012, revisions to previous estimates increased proved reserves by a net amount of 503 MBOE. These revisions mainly consisted of increased estimates of future production, associated with well workovers performed during 2012 and improved well performance based on recent drilling results.

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WHITING USA TRUST II

NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS — (Continued)

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 — Oiland Gas. Future cash inflows as of December 31, 2013 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, 2013) to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming the continuation of existing economic conditions. The standardized measure of discounted future net cash flows has not been reduced by federal or state income taxes due to taxable income being passed through to the unitholders of the Trust.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves attributable to the Trust is as follows:

	December 31,
	2013			2012
Future cash inflows	$	616,381,470		$	707,151,510
Future production costs		(287,849,430	)		(318,880,620	)
Future development costs		(28,361,160	)		(23,669,280	)
Future net cash flows		300,170,880			364,601,610
10% annual discount for estimated timing of cash flows		(75,106,440	)		(98,212,140	)
Standardized measure of discounted future net cash flows(1)	$	225,064,440		$	266,389,470

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

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

	December 31,
	2013			2012
Beginning of year	$	266,389,470		$	323,597,250
Sale of oil and gas produced, net of production costs		(65,801,922	)		(69,734,756	)
Sale of minerals in place		—			—
Net changes in prices and production costs		3,010,352			(36,449,575	)
Extensions and discoveries less related costs		(18,348	)		161,892
Previously estimated development costs incurred during the period		4,452,623			5,379,659
Changes in estimated future development costs		(9,401,796	)		(5,211,077	)
Revisions of previous quantity estimates		(204,886	)		16,286,352
Accretion of discount		26,638,947			32,359,725
End of year	$	225,064,440		$	266,389,470

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WHITING USA TRUST II

NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS — (Continued)

Future cash inflows 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, 2013 as follows:

	2013		2012		2011
Oil (per Bbl)	$	87.22	$	86.55	$	87.15
Gas (per Mcf)	$	5.05	$	5.00	$	6.04

11. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

	Three Months Ended
Year Ended December 31, 2013	March 31		June 30		September 30		December 31		Total
Income from net profits interest	$	12,180,733	$	11,936,618	$	13,814,090	$	16,553,937	$	54,485,378
Distributable income	$	11,975,068	$	11,626,972	$	13,604,258	$	16,343,858	$	53,550,156
Distributions per unit	$	0.650819	$	0.631901	$	0.739362	$	0.888253	$	2.910335
Year Ended December 31, 2012
Income from net profits interest	$	—	$	18,078,189	$	16,594,046	$	14,350,918	$	49,023,153
Distributable income	$	—	$	17,563,791	$	16,455,602	$	13,995,405	$	48,014,798
Distributions per unit	$	—	$	0.954554	$	0.894326	$	0.760620	$	2.609500

******

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Whiting Petroleum Corporation

Denver, Colorado

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

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

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

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

/s/ Deloitte & Touche LLP

Denver, Colorado

March 2, 2012

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UNDERLYING PROPERTIES

Statements of Historical Revenues

and Direct Operating Expenses

(In thousands)

	Year Ended December 31,
	2011		2010
Net Revenues:
Oil sales	$	120,879	$	104,667
Natural gas sales		16,893		19,041
Total revenues	$	137,772	$	123,708
Direct operating expenses:
Lease operating expenses	$	39,377	$	37,391
Production taxes		7,536		6,571
Total direct operating expenses	$	46,913	$	43,962
Excess of revenues over direct operating expenses	$	90,859	$	79,746

The accompanying notes are an integral part of this statement.

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UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF HISTORICAL REVENUES

AND DIRECT OPERATING EXPENSES

For the years ended December 31, 2011 and 2010

1. UNDERLYING PROPERTIES

The accompanying statements present the revenues and direct operating expenses for the years ended December 31, 2011 and 2010 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 conveyed to the Trust the right to receive 90% of the term net proceeds from these Underlying Properties (“Net Profits Interest”), with Whiting retaining title to the Underlying Properties.

2. BASIS OF PRESENTATION

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

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

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UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF HISTORICAL REVENUES

AND DIRECT OPERATING EXPENSES — (Continued)

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, 2011 and 2010:

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

There is significant competition among purchasers of crude oil and natural gas and if Whiting were to lose any of its largest purchasers of oil and gas from the underlying properties, several entities could reasonably be expected to purchase crude oil and natural gas produced from the underlying properties with little or no interruption to their business.

3. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

Estimates of proved reserves attributable to the Trust and the related valuations were based on reports prepared by the Trust’s independent petroleum engineers Cawley, Gillespie & Associates, Inc. Proved reserve estimates included herein conform to the definitions prescribed by the FASB and SEC. 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.

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UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF HISTORICAL REVENUES

AND DIRECT OPERATING EXPENSES — (Continued)

As of December 31, 2011, all of the underlying properties’ oil and gas reserves are attributable to properties within the United States. The following is a summary of the changes in quantities of proved oil and gas reserves attributable to the underlying properties (on a full economic life basis) for the years ended December 31, 2010 and 2011:

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

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

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

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UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF HISTORICAL REVENUES

AND DIRECT OPERATING EXPENSES — (Continued)

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

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

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

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves attributable to the underlying properties (on a full economic life basis) is as follows (in thousands):

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

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

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UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF HISTORICAL REVENUES

AND DIRECT OPERATING EXPENSES — (Continued)

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

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

Future cash inflows 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, 2011 as follows:

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

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures.    The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by Whiting to The Bank of New York Mellon Trust Company, N.A., as Trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, the Trustee carried out an evaluation of the Trustee’s disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.

Due to the contractual arrangements of (i) the Trust agreement and (ii) the conveyance of the NPI, the Trustee relies on (A) information provided by Whiting, including historical operating data, plans for future operating and capital expenditures, reserve information and information relating to projected production, and (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers. See Risk Factors “The Trust and the Trust unitholders have no voting or managerial rights with respect to the underlying properties. As a result, neither the Trust nor the unitholders have any ability to influence the operation of the underlying properties” and “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report on Form 10-K, for a description of certain risks relating to these arrangements and reliance on information when reported by Whiting to the Trustee and recorded in the Trust’s results of operation.

Changes in Internal Control over Financial Reporting.    During the quarter ended December 31, 2013, there has been no change in the Trustee’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trustee’s internal control over financial reporting relating to the Trust. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of Whiting.

Trustee’s Annual Report on Internal Control Over Financial Reporting.    A registrant’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A registrant’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the registrant; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the registrant are being made only in accordance with authorizations of management and directors of the registrant; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the registrant’s assets that could have a material effect on the financial statements.

The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities and Exchange Act of 1934, as amended. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with the modified cash basis of accounting. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting

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based on the criteria established inInternal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework inInternal Control — Integrated Framework (1992), the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2013.

Deloitte & Touche, LLP, the Trust’s independent registered public accounting firm that audited the financial statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Trust’s internal control over financial reporting.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

March 13, 2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Trustee and Unit Holders of

Whiting USA Trust II

c/o The Bank of New York Mellon Trust Company, N.A., Trustee

Austin, Texas

We have audited the internal control over financial reporting of Whiting USA Trust II (the “Trust”) as of December 31, 2013, based on criteria established inInternal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Trustee is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Trustee’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Trust’s internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A trust’s internal control over financial reporting is a process designed by, or under the supervision of, the trust’s trustee, and effected by the trustee and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the comprehensive basis of accounting described in Note 2 to the financial statements. A trust’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the comprehensive basis of accounting described in Note 2 of the financial statements, and that receipts and expenditures of the trust are being made only in accordance with authorization of the Trustee; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the trust’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper trustee override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established inInternal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2013 of the Trust and our report dated March 13, 2014 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Trust’s basis of accounting.

/s/ Deloitte & Touche LLP

Austin, Texas

March 13, 2014

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Item 9B. Other Information

None.

P A R T    I I I

Item 10. Directors, Executive Officers and Corporate Governance

The Trust has no directors or executive officers. The Trustee is a corporate trustee that may be removed by the affirmative vote of the holders of not less than a majority of the outstanding Trust units at a meeting at which a quorum is present.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act of 1934 requires the holders of more than 10 percent of the Trust units to file with the SEC reports regarding their ownership and changes in ownership of the Trust units. The Trustee is not aware of any 10 percent unitholder having failed to comply with all Section 16(a) filing requirements in 2013.

Audit Committee and Nominating Committee

Because the Trust does not have a board of directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.

Code of Ethics

The Trust does not have a principal executive officer, principal financial officer, principal accounting officer or controller and, therefore, has not adopted a code of ethics applicable to such persons. However, employees of the Trustee must comply with the bank’s code of ethics.

Item 11. Executive Compensation

During the year ended December 31, 2013 the Trustee received administrative fees from the Trust in the amount of $175,000. The Trust does not have any executive officers, directors or employees. Because the Trust does not have a board of directors, it does not have a compensation committee.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

(a)    Security Ownership of Certain Beneficial Owners.

Based on a review of SEC filings, the Trustee is not aware of any holders of 5% or more of the units.

(b)    Security Ownership of Management.

Not applicable.

(c)    Changes in Control.

The registrant knows of no arrangement, including any pledge by any person of securities of the registrant or any of its parents, the operation of which may at a subsequent date result in a change of control of the registrant.

Item 13. Certain Relationships, Related Transactions and Director Independence

Letter of Credit

In June 2012, Whiting established a $1.0 million letter of credit for the Trustee in order to provide it with a mechanism to pay the operating expenses of the Trust, in the event that Whiting should fail to lend funds to the Trust if requested to do so by the Trustee. This letter of credit will not be used to fund NPI distributions to unitholders, and Whiting has no obligation to lend funds to the Trust. If the Trustee were to draw on the letter of credit or borrow funds from Whiting or otherwise, no further distributions would be made to the unitholders until all such amounts have been repaid by the Trust.

Plugging and Abandonment

During the year ended December 31, 2013, Whiting incurred $1.2 million of plugging and abandonment costs on the underlying properties. Pursuant to the terms of the conveyance agreement, plugging and abandonment charges relating to the underlying properties, net of any proceeds received from the salvage of equipment, are funded entirely by Whiting and are not therefore included as a deduction in the calculation of net proceeds or otherwise deducted from Trust unitholders over the term of the Trust.

Operating Overhead

Pursuant to the terms of the 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. For the year ended December 31, 2013, the Trust’s portion of the monthly charge totaled $1.7 million and averaged $431 per month per active operated well. 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.

Administrative Services

Under the terms of the administrative services agreement, the Trust pays a quarterly administration fee of $50,000 to Whiting 60 days following the end of each calendar quarter. General and administrative expenses in

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the Trust’s statements of distributable income for the year ended December 31, 2013 include $200,000 for quarterly administrative fees paid to Whiting.

The administrative services agreement will expire upon the termination of the net profits interest unless earlier terminated by mutual agreement of the Trustee and Whiting.

Trustee Administration Fee

Under the terms of the Trust agreement, the Trust pays an annual administrative fee to the Trustee of $175,000, which is paid in four quarterly installments of $43,750 each and is billed in arrears. Starting in 2017, such fee escalates by 2.5% each year. General and administrative expenses in the Trust’s statements of distributable income for the year ended December 31, 2013 include $175,000 for quarterly administrative fees paid to the Trustee.

Director Independence

The Trust does not have a board of directors and therefore no determination been made relative to director independence.

Item 14. Principal Accountant Fees and Services

The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustee. The Trustee has appointed Deloitte & Touche, LLP (“Deloitte”) as the independent registered public accounting firm to audit the Trust’s financial statements for the fiscal year ended December 31, 2014. During fiscal 2013, Deloitte served as the Trust’s independent registered public accounting firm.

The following table presents the aggregate fees billed to the Trust for the fiscal years ended December 31, 2013 and 2012 by Deloitte:

	2013		2012
Audit fees(1)	$	195,000	$	190,000
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—
Total fees	$	195,000	$	190,000

(1) Fees for audit services in 2013 and 2012 consisted of the audit of the Trust’s annual financial statements and reviews of the Trust’s quarterly financial statements.

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P A R T    I V

Item 15. Exhibits and Financial Statement Schedules

(a)(1) Financial Statements

Refer to the Index to Whiting USA Trust II Financial Statements included in Item 8 of this Annual Report on Form 10-K for a list of all financial statements filed as part of this report.

(a)(2) Schedules

Schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.

(a)(3) Exhibits

See Exhibit Index.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

WHITING USA TRUST II
By:	THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.
	By:	/s/     MIKE ULRICH
		Mike Ulrich
		Vice President

March 13, 2014

The Registrant, Whiting USA Trust II, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that such function exists pursuant to the terms of the Trust agreement under which it serves.

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Appendix 1

Cawley, Gillespie & Associates, Inc.

PETROLEUM CONSULTANTS

13640 BRIARWICK DRIVE,	306 WEST SEVENTH STREET,	1000 LOUISIANA STREET,
SUITE 100 AUSTIN,	SUITE 302 FORT WORTH,	SUITE 625 HOUSTON,
TEXAS 78729-1707	TEXAS 76102-4987	TEXAS 77002-5008
512-249-7000	817-336-2461	713-651-9944
	www.cgaus.com

January 31, 2014

Whiting USA Trust II

1700 Broadway, Suite 2300

Denver, Colorado 80290-2300

Re:	Evaluation Summary – SEC Price
	Whiting USA Trust II Underlying Properties
	Total Proved Reserves
	Certain Properties Located in Various States As of December 31, 2013
	Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue

Gentlemen:

As requested, we are submitting our estimates of total proved reserves and forecasts of economics attributable to the underlying properties, from which a net profits interest has been formed and 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 January 31, 2014 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:

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		Underlying Properties Full Economic Life
		Proved Developed Producing			Proved Developed Behind Pipe		Proved Undeveloped		Total Proved
Net Reserves
Oil	- Mbbl		11,217.4			270.6		23.8		11,511.9
Gas	- MMcf		15,512.4			885.3		0.0		16,397.7
NGL	- Mbbl		563.0			3.1		0.0		566.2
Equivalent*	- Mbbl		14,365.8			421.3		23.8		14,811.0
Revenue
Oil	- M$		987,142.9			24,829.8		2,161.2		1,014,133.9
Gas	- M$		76,914.3			5,021.0		0.0		81,935.3
NGL	- M$		36,640.5			117.1		0.0		36,757.6
Severance Taxes	- M$		56,159.3			1,524.1		108.1		57,791.5
Ad Valorem Taxes	- M$		32,465.1			969.2		130.8		33,565.0
Operating Expenses	- M$		527,294.4			5,567.6		605.5		533,467.6
Investments	- M$		29,892.9	��		1,792.9		619.5		32,305.3
Net Operating Income	- M$		454,886.0			20,114.1		697.3		475,697.3
Discounted @ 10%	- M$		287,887.3			6,907.0		389.1		295,183.5

		Underlying Properties Reserves Estimated to be Produced by December 31, 2021
		Proved Developed Producing		Proved Developed Behind Pipe		Proved Undeveloped		Total Proved
Net Reserves
Oil	- Mbbl		6,877.8		41.4		17.9		6,937.1
Gas	- MMcf		10,892.9		163.0		0.0		11,055.9
NGL	- Mbbl		274.6		0.0		0.0		274.6
Equivalent*	- Mbbl		8,967.9		68.6		17.9		9,054.4
Revenue
Oil	- M$		606,862.8		3,779.1		1,624.7		612,266.6
Gas	- M$		54,924.9		952.1		0.0		55,877.0
NGL	- M$		16,724.7		0.0		0.0		16,724.7
Severance Taxes	- M$		35,544.0		245.2		81.2		35,870.5
Ad Valorem Taxes	- M$		19,556.2		174.5		98.3		19,829.0
Operating Expenses	- M$		263,480.6		383.0		269.7		264,133.4
Investments	- M$		29,892.9		1,000.0		619.5		31,512.4
Net Operating Income	- M$		330,038.6		2,928.4		555.9		333,522.9
Discounted @ 10%	- M$		247,849.3		1,885.3		337.0		250,071.5

* 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 $96.78 per bbl and $3.67 per MMBtu, respectively, were adjusted individually to WTI posted pricing at $93.55 per bbl and Houston Ship Channel pricing at $3.65 per MMBtu, as of December 31, 2013. 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 $88.09 per bbl of oil, $64.93 per bbl of natural gas liquids and $5.00 per mcf of natural gas. For the proved reserves of the underlying properties

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estimated to be produced by December 31, 2021, the average adjusted prices were $88.26 per bbl of oil, $60.91 per bbl of natural gas liquids and $5.05 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 is 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.

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 havenot 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 costs of plugging and abandonment, less proceeds from the salvage value of equipment and/or facilities, have been included where material.

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

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

Yours very truly,

/s/ Robert D. Ravnaas

Robert D. Ravnaas, P.E.

President

Cawley, Gillespie & Associates

Texas Registered Engineering Firm F-693

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APPENDIX

Explanatory Comments for Individual Tables

HEADINGS

Table Number

Effective Date of the Evaluation

Identity of Interest Evaluated

Reserve Classification and Development Status

Operator – Property Name

Field (Reservoir) Names – County, State

FORECAST

(Columns)
(1)(11)(21)	Calendar orFiscal 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.

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	Appendix
	Page 1

(Columns)
(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.

Cawley, Gillespie & Associates, Inc.
	Appendix
	Page 2

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 andmay 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

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estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

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

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

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APPENDIX

Reserve Definitions and Classifications

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    “(ii)    Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

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    “(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 ispermitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

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

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

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Cawley, Gillespie & Associates, Inc.

PETROLEUM CONSULTANTS

13640 BRIARWICK DRIVE,	306 WEST SEVENTH STREET,	1000 LOUISIANA STREET,
SUITE 100 AUSTIN,	SUITE 302 FORT WORTH,	SUITE 625 HOUSTON,
TEXAS 78729-1707	TEXAS 76102-4987	TEXAS 77002-5008
512-249-7000	817-336-2461	713-651-9944
	www.cgaus.com

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 President in 2011. 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.

INDEX TO EXHIBITS

Exhibit Number	Description
3.1*	Certificate of Trust of Whiting USA Trust II [Incorporated herein by reference to Exhibit 3.3 to the Registration Statement on Form S-1 (Registration No. 333-178586)].
3.2*	Amended and Restated Trust Agreement, dated March 28, 2012, by and among Whiting Oil and Gas Corporation, The Bank of New York Mellon Trust Company, N.A. as Trustee and Wilmington Trust, National Association, as Delaware Trustee. [Incorporated herein by reference to Exhibit 3.1 to the Trust’s Current Report on Form 8-K filed on March 28, 2012 (File No. 001-35459)].
10.1*	Conveyance and Assignment, dated March 28, 2012, from Whiting Oil and Gas Corporation to The Bank of New York Mellon Trust Company, N.A. as Trustee of Whiting USA Trust II [Incorporated herein by reference to Exhibit 10.1 to the Trust’s Current Report on Form 8-K filed on March 28, 2012 (File No. 001-35459)].
10.2*	Administrative Services Agreement, dated March 28, 2012, by and between Whiting Oil and Gas Corporation and Whiting USA Trust II [Incorporated herein by reference to Exhibit 10.2 to the Trust’s Current Report on Form 8-K filed on March 28, 2012 (File No. 001-35459)].
31	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99	Report of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers dated January 31, 2014 [Incorporated by reference to Appendix 1 of this Annual Report on Form 10-K for the year ended December 31, 2013 filed on March 13, 2014 (File No. 001-35459)].

(* Asterisk indicates exhibit previously filed with the SEC and incorporated herein by reference.)