10-K 1 d446461d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

(Mark One)

 

þ

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

for The Fiscal Year Ended December 31, 2012

 

¨

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 001-34026

 

 

WHITING USA TRUST I

(Exact name of registrant as specified in its charter)

 

Delaware

 

26-6053936

(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

Global Corporate Trust

919 Congress Avenue

Austin, Texas

 

78701

(Address of principal executive offices)   (Zip Code)

                                   1-800-852-1422                                   

(Registrant’s telephone number, including area code)

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  þ.

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   þ.

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  þ  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.  þ

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 þ    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  þ

The aggregate market value of Units of Beneficial Interest in Whiting USA Trust I held by non-affiliates at the closing sales price on June 30, 2012 of $17.71 was $206,808,525.

As of March 15, 2013, 13,863,889 Units of Beneficial Interest in Whiting USA Trust I were outstanding.

Documents Incorporated By Reference: None

 

 

 

 


Table of Contents

TABLE OF CONTENTS

 

Forward-Looking Statements

     3   

Glossary of Certain Definitions

     5   
PART I   

Item 1.

  Business      10   

Item 1A.

  Risk Factors      28   

Item 1B.

  Unresolved Staff Comments      43   

Item 2.

  Properties      44   

Item 3.

  Legal Proceedings      53   

Item 4.

  Mine Safety Disclosures      53   
PART II   

Item 5.

  Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities      54   

Item 6.

  Selected Financial Data      55   

Item 7.

  Trustee’s Discussion and Analysis of Financial Condition and Results of Operations      56   

Item 7A.

  Quantitative and Qualitative Disclosure About Market Risk      66   

Item 8.

  Financial Statements and Supplementary Data      68   

Item 9.

  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      83   

Item 9A.

  Controls and Procedures      83   

Item 9B.

  Other Information      87   
PART III   

Item 10.

  Directors, Executive Officers and Corporate Governance      87   

Item 11.

  Executive Compensation      87   

Item 12.

  Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters      87   

Item 13.

  Certain Relationships and Related Transactions and Director Independence      88   

Item 14.

  Principal Accountant Fees and Services      90   
PART IV   

Item 15.

  Exhibits and Financial Statement Schedules      91   

 

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References to the “Trust” in this document refer to Whiting USA Trust I. References to “Whiting” in this document refer to Whiting Petroleum Corporation and its wholly-owned 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 and the successor to Equity Oil Company. Equity Oil Company was merged into Whiting Oil and Gas Corporation effective September 30, 2009. The merger did not have an effect on the Trust.

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 of oil and natural gas wells;

 

   

future production costs;

 

   

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

 

   

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

 

   

the effect of existing and future laws and regulatory actions;

 

   

competition from others in the energy industry;

 

   

inflation or deflation; and

 

   

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

 

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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.

“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.

“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.

 

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“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.”

“FASB” Financial Accounting Standards Board.

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

“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 wells” The total wells 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.

“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 of natural gas.

“MMBOE” One million BOE.

“MMBtu” One million Btu.

 

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“MMcf” One million standard cubic feet of natural gas.

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

“net profits interest (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.

“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 PV 10%” The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Securities and Exchange Commission (“SEC”) guidelines, net of estimated lease operating expense, production taxes and future development costs, using costs and prices (prices being the 12-month average price calculated using the first-day-of-the-month price for each of the 12 months that make up the reporting period) as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or Federal income taxes and discounted using an annual discount rate of 10%. Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC.

“proved developed 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.

 

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

 

  a.

The area identified by drilling and limited by fluid contacts, if any, and

 

  b.

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

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

 

  a.

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and

 

  b.

The project has been approved for development by all necessary parties and entities, including governmental entities.

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

“proved undeveloped reserves” Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. 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,

 

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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 or operating of the affected well.

“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 United States Securities and Exchange Commission.

“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 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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PART I

Item 1. Business

General

Whiting USA Trust I is a statutory trust formed in October 2007 under the Delaware Statutory Trust Act, pursuant to a trust agreement (the “Trust agreement”) among Whiting Oil and Gas as trustor, The Bank of New York Trust Company, N.A., as Trustee (subsequently renamed The Bank of New York Mellon Trust Company, N.A., and hereinafter referred to as “Trustee”) and Wilmington Trust Company as Delaware Trustee (the “Delaware Trustee”). The initial capitalization of the Trust estate was funded by Whiting in November 2007. 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 1-800-852-1422.

The Trust makes copies of its reports under the Exchange Act available at http://whx.investorhq.businesswire.com. The Trust’s filings under the Exchange Act are also available electronically from the website maintained by the Securities and Exchange Commission (“SEC”) at http://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, 2007, the Trust had no assets other than a de minimus cash balance from its initial capitalization and had conducted no operations other than organizational activities. In April 2008, the Trust issued 13,863,889 units of beneficial interest in the Trust (“Trust units”) to Whiting in exchange for the conveyance of a term net profits interest (“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, Mid-Continent, Permian Basin and Gulf Coast regions. The underlying properties include interests in 3,081 gross (368.0 net) producing oil and gas wells. Immediately after the conveyance, Whiting completed an initial public offering of Trust units selling 11,677,500 such units. Whiting retained ownership of 2,186,389 Trust units, or 15.8% of the total Trust units issued and outstanding.

The NPI will terminate when 9.11 MMBOE have been produced and sold from the underlying properties (which amount is the equivalent of 8.20 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the 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, 2012, on a cumulative accrual basis 6.10 MMBOE (74%) of the Trust’s total 8.20 MMBOE have been produced and sold and a cumulative 0.02 MMBOE have been divested. Further detail on the reserves is provided herein under the section titled “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, 2012, which we refer to as the “reserve report.” According to the

 

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reserve report, the portion of the 9.11 MMBOE (8.20 MMBOE at the 90% NPI) reserve quantities attributable to the NPI not yet produced or sold as divestitures at December 31, 2012 is projected to be produced from the underlying properties by June 30, 2015, 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, 2012 was approximately 63% oil and approximately 37% 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, all royalties, lease operating expenses (including costs of workovers), production and property taxes, hedge payments made by Whiting to the hedge contract counterparty, maintenance expenses, postproduction costs (including plugging and abandonment liabilities) and producing overhead. If at any time costs should exceed gross proceeds, neither the Trust nor the Trust unitholders would be liable for the excess costs. The Trust however, would not receive any net proceeds until future net proceeds exceed the total of those excess costs, plus interest at the prime rate. For more information on the net proceeds calculation, see “Computation of Net Proceeds” later in this section.

Whiting entered into certain costless collar hedge contracts and in turn conveyed to the Trust the rights and obligations to hedge payments under such contracts. All such contracts terminated as of December 31, 2012, and no additional hedges are allowed to be placed on the Trust assets.

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.

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 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 a 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

 

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underlying properties. The business and affairs of the Trust are managed 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 2012, sales to Lion Oil Company, Enterprise South Texas and Plains Marketing LP accounted for 17%, 15% and 11%, respectively, of total oil and natural gas sales from the underlying properties. 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 one or both of their largest purchasers, several entities could reasonably be expected to purchase crude oil and natural gas produced from the underlying properties without significant interruption to the sales.

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,

 

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conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas. Future price fluctuations for oil, natural gas and natural gas liquids will directly impact Trust distributions, estimates of reserves attributable to the Trust’s interests and estimated and actual future net revenues to the Trust.

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

 

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Unless otherwise required by the Trust agreement, a matter may be approved or disapproved by the vote of a majority of the Trust units held by the Trust unitholders at a meeting where there is a quorum. This is true even if a majority of the total Trust units did not approve it. In determining whether the holders of the required number of units have approved any matter that is submitted to a vote of unitholders, those units owned by Whiting will be disregarded if such matter either would result in increased costs and expenses to the Trust or would adversely affect the economic interests of Trust unitholders. The affirmative vote of the holders of a majority of the outstanding Trust units is required to:

 

   

dissolve the Trust;

 

   

remove the Trustee or the Delaware Trustee;

 

   

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

 

   

merge or consolidate the Trust with or into another entity;

 

   

approve the sale of assets of the Trust unless the sale involves the release of less than or equal to 0.25% of the total production from the underlying properties for the last twelve months and the aggregate asset sales do not have a fair market value in excess of $500,000 for the last twelve months; or

 

   

agree to amend or terminate the conveyance.

In addition, certain amendments to the Trust agreement, conveyance, administrative services agreement and registration rights agreement may be made by the Trustee without approval of the Trust unitholders. The Trustee must consent before all or any part of the Trust assets can be sold, except in connection with the dissolution of the Trust or limited sales directed by Whiting in conjunction with its sale of underlying properties.

Termination of the Trust; Sale of the Net Profits Interest

The NPI will terminate at the time when 9.11 MMBOE (8.20 MMBOE at the 90% NPI) have been produced and sold from the underlying properties, and the Trust will soon thereafter wind up its affairs and terminate, after which it will pay no further distributions. The Trust will dissolve prior to the termination of the NPI if:

 

   

the Trust sells the NPI;

 

   

annual gross proceeds to the Trust attributable to the NPI are less than $1.0 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 terminated.

 

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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 computation of net proceeds. For more detailed provisions concerning the NPI, we make reference to the conveyance agreement, which is listed 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 in April 2008 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:

 

   

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

 

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

a producing overhead charge in accordance with existing operating agreements;

 

   

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

 

   

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

 

   

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

 

   

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

 

   

costs and expenses for renewals or extensions of leases.

All of the hedge payments received by Whiting from the counterparty upon settlements of hedge contracts and certain other non-production revenues, as detailed in the conveyance, will offset the operating expenses outlined above in calculating the net proceeds. If the hedge payments received by Whiting and certain other non-production revenues exceed the operating

 

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expenses during a quarterly period, the ability to use 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 are less than such expenses. If any excess amounts have not been used to offset costs at the time when 9.11 MMBOE (8.20 MMBOE at the 90% NPI) have been produced and sold from the underlying properties, which is the time when the NPI will terminate, then unitholders will not be entitled to receive the benefit of such excess amounts.

Although capital expenditures for the testing, drilling, completion, equipping, plugging back or recompletion of any well that is a part of the underlying properties cannot be deducted from gross proceeds pursuant to the terms of the conveyance agreement, Whiting incurred capital expenditures of $6.8 million on the underlying properties in 2012. Such expenditures were not deducted from gross proceeds or Trust distributions in 2012, but they may have the effect of ultimately accelerating the receipt of NPI net proceeds and thereby benefiting Trust unitholders by accelerating their return on investment. The Trust cannot provide any assurance that this will continue to occur or that future capital expenditures will be consistent with historical levels.

Pursuant to the terms of the applicable joint operating agreements, Whiting deducts from the gross proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally, for 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 $419 per month per active operated well, which totaled $1.7 million for the four distributions made during the year ended December 31, 2012. 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 hedge payments Whiting made or received under such

 

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costless collar hedge contracts. These contracts were entered into to reduce the exposure to volatility in the underlying properties’ oil and gas revenues due to fluctuations in crude oil and natural gas prices, and to achieve more predictable cash flows. Historically, prices received for oil and gas 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 oil and gas production. The hedge contracts were placed with a single trading counterparty, JPMorgan Chase Bank National Association and were in place during the 2012, 2011 and 2010 periods presented in this Annual Report on Form 10-K. However, all hedging contracts terminated as of December 31, 2012. No additional hedges are allowed to be placed on Trust assets, nor can the Trust enter into derivative contracts for trading or speculative 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. Natural gas costless collar arrangements settle based on the closing settlement price on the second to last scheduled trading day of the month prior to delivery. In a collar arrangement, the counterparty is required to make a payment to Whiting for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. Whiting is required to make a payment to the counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price.

The amount received by Whiting from the hedge contract counterparty upon settlements of the hedge contracts reduces the operating expenses related to the underlying properties in calculating net proceeds. In addition, the aggregate amount paid by Whiting on settlement of the hedge contracts reduces the amount of net proceeds paid to the Trust.

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

 

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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.

As the designated operator of a property comprising the underlying properties, Whiting may enter into farm-out, operating, participation and other similar agreements to develop the property. Whiting may enter into any of these agreements without the consent or approval of the Trustee or any Trust unitholder.

Whiting 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 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 proposed Treasury regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. 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

 

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unincorporated business entity. No ruling has been or will be requested from the Internal Revenue Service, which we refer to as 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 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.

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

 

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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 1-800-852-1422, 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 2012 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://whx.investorhq.businesswire.com.

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 discharge of materials into the environment. These laws and regulations may, among other things:

 

   

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

 

   

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

 

   

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

 

   

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

 

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Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, these laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly 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, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency (“EPA”) the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. In its operations at the underlying properties, Whiting generates solid and hazardous wastes that are subject to RCRA and comparable state laws. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. In September 2010, the Natural Resources Defense Council filed a petition with the EPA, requesting them to reconsider the RCRA exemption for exploration, production and development wastes but, to date, the agency has not taken any action on the petition. 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 the 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

 

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the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. While Whiting generates materials in the course of its operations of the underlying properties that may be regulated as hazardous substances, Whiting has not been notified that it has been named as a potentially responsible party at or with respect to any Superfund sites. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

The underlying properties 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 was not under Whiting’s control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, Whiting could be required to remove previously disposed substances and wastes, remediate contaminated property, perform remedial plugging or pit closure operations to prevent future contamination or to pay some or all of the costs of any such action.

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

Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. Hydraulic fracturing has been utilized 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 took the position that hydraulic fracturing

 

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operations using diesel are subject to regulation under the Underground Injection Control program of the Safe Drinking Water Act as Class II wells and has commenced drafting guidance for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel. Industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities on drinking water resources. The EPA published a progress report of the study in December 2012 and expects to release the final results by 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 by 2014 that such wastewater must meet before being transported to a treatment plant. Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy (“DOE”), the U.S. Government Accountability Office and the White House Council for Environmental Quality. The U.S. Department of the Interior is also considering regulation of hydraulic fracturing activities on public lands. In addition, the Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. For example, on June 17, 2011, Texas enacted a law that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production) and the public. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Further, at least three local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities. No assurance can be given as to whether or not similar measures might be considered or implemented in the jurisdictions in which the underlying properties are located. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, 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.

 

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

 

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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, on April 17, 2012, the EPA finalized rules that would establish 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 would require the application of reduced emission completion techniques for completion of newly drilled and fractured wells in addition to existing wells that are refractured. The 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 require that Whiting organize and/or disclose information about hazardous materials used or produced in its operations. Whiting believes that it is in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Endangered Species Considerations. The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered and threatened species or their habitats. If endangered species are located in areas of the underlying properties where Whiting or the other underlying property operators wish to conduct seismic surveys, development activities or abandonment operations, the work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the ESA. Under the September 9, 2011 settlement, the federal agency is required to begin issuing decisions with respect to the 250 candidate species by the end of 2011 and no later than the end of the 2013 fiscal year. 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.

 

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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”), the National Environmental Policy Act (“NEPA”) and the Coastal Zone Management Act (“CZMA”) 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. CZMA, on the other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands associated with various uses, including offshore oil and gas development. In obtaining various approvals from the Department of Interior, Whiting must certify that it will conduct its activities in a manner consistent with all applicable regulations.

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, 2012 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 2013 with respect to these properties. However, there is no assurance that the passage of more stringent laws or implementing regulations in the future will not have a negative impact on the operations of these properties and the cash distributions to the Trust unitholders.

 

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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 at termination of the Trust.

The trading price for publicly traded securities similar to the Trust units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the Trust will vary in response to numerous factors outside the control of the Trust, including prevailing sales prices of oil, natural gas and natural gas liquids production attributable to the underlying properties. Consequently, the market price for the Trust units may not necessarily be indicative of the value that the Trust would realize if it sold the 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 made to a unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the unitholder, and over time the market price of the Trust units will decline to zero at termination of the Trust.

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

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

 

   

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

 

   

the actions of the Organization of Petroleum Exporting Countries;

 

   

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

 

   

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

 

   

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

 

   

the effects of global credit, financial and economic issues;

 

   

the level of global oil and natural gas inventories;

 

   

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

 

   

weather conditions;

 

   

technological advances affecting energy consumption;

 

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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.

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

Whiting entered into certain costless collar hedge contracts, which were conveyed to the Trust to reduce the exposure to volatility in the underlying properties’ oil and gas revenues due to fluctuations in crude oil and natural gas prices, and to achieve more predictable cash flows. However, all such costless collar hedge contracts terminated as of December 31, 2012, and no additional hedges are allowed to be placed on the Trust assets. The amount of the cash settlement gains received on commodity derivatives attributable to the costless collar hedge contracts for the years ended December 31, 2012, 2011 and 2010 totaled $5.9 million, $4.5 million and $4.3 million, respectively. Assuming prior period crude oil and natural gas prices and production are similar to future periods, the termination of the costless collar hedge contracts as of the end of 2012 would result in reduced future cash distributions to unitholders due to no cash settlement gains on derivatives to be received in future periods.

 

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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. The reserves attributable to the underlying properties are depleting assets, which means that the reserves attributable to the underlying properties will decline over time. The reserve report reflects that the cumulative past production from the underlying properties through December 31, 2012 represents an aggregate depletion percentage of 94.2% of the estimated ultimate total production from the properties. As a result, the quantity of oil and natural gas produced from the underlying properties is expected to decline over time. Total oil and natural gas production attributable to the underlying properties declined 5.9% from 2008 to 2009, 11.8% from 2009 to 2010 and 8.8% from 2010 to 2011, and remained consistent from 2011 to 2012. Also based on the 2012 reserve report, overall production for both oil and gas attributable to the underlying properties is expected to decline at rates ranging from 9% to 11% annually from 2013 through the estimated June 30, 2015 NPI termination date. 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 when 9.11 MMBOE (8.20 MMBOE at the 90% NPI) have been produced and sold from the underlying properties, which is projected by the reserve report to occur by June 30, 2015. As of December 31, 2012, on a cumulative accrual basis 6.10 MMBOE of the Trust’s total 8.20 MMBOE have been produced and sold and a cumulative reserve quantity of 0.02 MMBOE have been divested. Furthermore, 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 NPI to replace the depleting assets and production attributable 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 expected by Whiting or estimated in the reserve report. In addition, Whiting is not required to make any capital expenditures.

 

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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.

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

The value of the Trust units and the amount of future cash distributions to the Trust unitholders will depend upon, among other things, the accuracy of the production and reserves estimated to be attributable to the underlying properties and the 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 estimated future net revenues 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 will depend upon, among other things, oil, natural gas and natural gas liquid production and prices and the costs incurred to exploit oil and natural gas reserves attributable to the underlying properties. Drilling, production or transportation accidents that temporarily or permanently halt the production and sale of oil, natural gas and natural gas liquids at any of the underlying properties will reduce Trust distributions by reducing the amount of net proceeds available for distribution. For example, accidents may occur that result

 

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in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any costs incurred in connection with any such accidents that are not insured against will have the effect of reducing the net proceeds available for distribution to the Trust. Also, Whiting does not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. 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, 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 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.

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 and cash available for distribution to Trust unitholders.

Whiting is currently designated as the operator of approximately 65% of the underlying properties based on the December 31, 2012 standardized measure of discounted future net cash flows. However, for the 35% of the underlying properties that it does not operate, Whiting does not have control over normal operating procedures or expenditures relating to such properties.

 

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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 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 will be limited in its ability to do so.

Shortages or increases in costs of oil field equipment, services and qualified personnel 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. Shortages of field personnel and equipment or price increases could significantly decrease the amount of cash available for distribution to the Trust unitholders, or restrict operations on the underlying properties.

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.

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

Whiting has made capital expenditures on the underlying properties, which has increased production from the underlying properties. However, Whiting has no contractual obligation to

 

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make capital expenditures on the underlying properties in the future. Furthermore, for properties on which Whiting is not designated as the operator, the decision whether to make capital expenditures is made by the operator and Whiting has no control over the timing or amount of those capital expenditures. Whiting also has the right to non-consent and not participate in the capital expenditures on these properties, in which case Whiting and the Trust will not receive the production resulting from such capital expenditures. Accordingly, it is likely that capital expenditures with respect to the underlying properties will vary from and may be less than historical levels.

The amount of cash available for distribution by the Trust is reduced by the amount of any royalties, lease operating expenses, production and property taxes, maintenance expenses, post-production costs and producing overhead.

Production costs on the underlying properties are deducted in the calculation of the Trust’s share of net proceeds. In addition, production and property taxes and any costs or payments associated with post-production costs are deducted in the calculation of the Trust’s share of net proceeds. Accordingly, higher or lower production expenses, taxes and post-production costs directly decrease or increase the amount received by the Trust in respect of its NPI.

If production costs of the underlying properties exceed the proceeds of production, the Trust will not receive net proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest during the deficit period. If the 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 and premiums. Increases in the differential and decreases in the premium 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 9.11 MMBOE are produced from the underlying properties and sold, and it is not known when that will occur.

The NPI will terminate when 9.11 MMBOE have been produced and sold from the underlying properties (which amount is the equivalent of 8.20 MMBOE in respect of the Trust’s right to

 

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receive 90% of the net proceeds from such reserves pursuant to the NPI). The reserve report prepared by the Trust’s independent petroleum engineer dated as of December 31, 2012 (the “reserve report”) projects that 9.11 MMBOE will have been produced and sold from the underlying properties by June 30, 2015. However, the exact rate of production cannot be predicted with certainty and such amount may be produced before or after the date projected by the reserve report. If production attributable to the underlying properties is slower than estimated, then financial returns to Trust unitholders will be lower (assuming constant prices) because cash distributions attributable to such production will occur at a later date.

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 $1.0 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 when 9.11 MMBOE (8.20 MMBOE at the 90% NPI) have been produced and sold from the underlying properties. 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 likely diminish towards the end of the term of the NPI because the cash distributions from the Trust will cease at 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 has broad discretion over the timing and amount of operating expenditures and activities, including workover expenses and activities, which could result in higher costs being attributed to the NPI.

   

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.

 

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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 managed by the Trustee. The voting rights of a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The Trust agreement provides that the Trustee may only be removed and replaced by a vote of the holders of a majority of the outstanding Trust units at a special meeting of Trust unitholders called by either the Trustee or the holders of not less than 10% of the outstanding Trust units. Whiting owns approximately 15.8% of the outstanding Trust units. As a result, it may be difficult to remove or replace the Trustee without the approval of Whiting.

Trust unitholders have limited ability to enforce provisions of the 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 likely would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The Trust agreement expressly limits the Trust unitholders’ ability to directly sue Whiting or any other third party other than the Trustee. As a result, the unitholders will not be able to sue Whiting to enforce these rights.

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

Under the Delaware Statutory Trust Act, Trust unitholders 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

 

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time. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts on the operations of the underlying properties.

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

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

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

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

 

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

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

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

In addition, both houses of Congress have considered legislation to reduce emissions of GHG, and many states have already taken legal measures to reduce emissions of GHG, primarily through the development of GHG inventories, greenhouse gas permitting and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. In the absence of new legislation, the EPA is issuing new regulations that limit emissions of GHG associated with the operations of the underlying properties which will require Whiting to incur costs to inventory and reduce emissions of GHG associated with the operations of the underlying properties and which could adversely affect

 

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demand for the oil and natural gas produced. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG 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 Trust unitholders.

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

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing has been utilized during the completion of wells drilled on the underlying properties, and Whiting believes that it may also be used in the future. The process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel under the Safe Drinking Water Act’s Underground Injection Control Program and has commenced drafting guidance for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel. Industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities on drinking water resources. The EPA published a progress report of the study in December 2012 and expects to release the final results by 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 by 2014 that such wastewater must meet before being transported to a treatment plant. Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy (“DOE”), the U.S. Government Accountability Office and the White House Council for Environmental Quality. The U.S. Department of the Interior is also considering regulation of hydraulic fracturing activities on public lands. In addition, legislation called the Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. For example, on June 17, 2011, Texas enacted a law that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production) and the public. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to pursue legal proceedings against producers and service providers based

 

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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, at least three local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities. No assurance can be given as to whether or not similar measures might be considered or implemented in the jurisdictions in which the underlying properties are located. If new laws or regulations that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in the states where the underlying properties are located, such legal requirements could make it more difficult or costly for Whiting to carry out 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.

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 an 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 65% of the underlying properties based on the December 31, 2012 standardized measure of discounted future net cash flows. 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.

Whiting’s ability to perform its obligations related to the operation of the underlying properties and its obligations to the Trust will depend on Whiting’s future financial condition and

 

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

Whiting owns 15.8% of the Trust units. If Whiting sells these units, then the market price of the Trust units may be reduced. Whiting and the Trust have entered into a registration rights agreement pursuant to which the Trust has agreed to file a registration statement or shelf registration statement to register the resale of the remaining Trust units held by Whiting and any transferee of the Trust units upon request by such holders.

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 9.11 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 for 9.11 MMBOE (8.20 MMBOE at the 90% NPI) to be produced from the underlying properties for purposes of the NPI.

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 less advantageous tax treatment than they anticipated.

 

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

The U.S. federal income tax treatment of an investment in the Trust may be modified by administrative or legislative changes, or by judicial interpretation, at any time, possibly on a retroactive basis. For example, the Health Care and Education Affordability Reconciliation Act of 2010 includes a provision that, in taxable years beginning after December 31, 2012, subjects an individual having modified adjusted gross income in excess of $200,000 or ($250,000 for married taxpayers filing joint returns) to a “Medicare tax” equal generally to 3.8% of the lesser of such excess or the individual’s net investment income, which appears to include interest income derived from investments such as the Trust units as well as any net gain from the disposition of Trust units. In addition, beginning January 1, 2013, the highest marginal U.S. federal income tax rate for individuals increased to 39.6% for ordinary income and 20% on long-term capital gains. Moreover, these rates are subject to change by new legislation at any time.

 

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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.

 

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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 are located primarily in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions of the United States. The underlying properties include interests in 3,081 gross (368.0 net) producing oil and natural gas wells located in 166 fields on 206,716 gross (71,663 net) acres in 14 states. Whiting has acquired interests in these properties through various acquisitions that have occurred during its 28 year existence prior to the conveyance. For the year ended December 31, 2012, the net production attributable to the underlying properties was 1,204 MBOE or 3.3 MBOE/d. Whiting operates approximately 65% of the underlying properties based on the December 31, 2012 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 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. These landowners’ 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 revenue, 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 9.11 MMBOE (8.20 MMBOE at the 90% NPI) of production from the underlying properties. As of December 31, 2012, on a cumulative accrual basis 6.10 MMBOE (74%) of the Trust’s total 8.20 MMBOE have been produced and sold, a cumulative 0.02 MMBOE have been divested, and the remaining balance is expected to be produced by June 30, 2015 based on the Trust’s year-end 2012 reserve report. 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 9.11 MMBOE (8.20 MMBOE at the 90% NPI) 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.

 

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Whiting’s 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. In addition, the Trust units retained by Whiting represent 15.8% of the Trust units outstanding. Whiting’s retained ownership interests in the underlying properties and its ownership of Trust units considered together entitle Whiting to receive approximately 24.2% of the net proceeds from the underlying properties during the term of the Trust, thereby providing Whiting 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 these properties as a reasonably prudent operator in the same manner that it would operate them 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.

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 rates ranging from 9% to 11% annually from 2013 through the estimated June 30, 2015 NPI termination date. 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.

Reserves

As of December 31, 2012, 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, 2012 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, 2012) attributable to the Trust based on the term of its NPI and the underlying properties on a full economic life basis (dollars in thousands):

 

                                                           
    Whiting USA Trust I(2)
(90% NPI through June 2015)
    Underlying Properties
(100% Full Economic Life)
 
    Oil(3)
(MBbl)
    Natural Gas
(Mcf)
    MBOE     Oil(3)
(MBbl)
    Natural Gas
(Mcf)
    MBOE  

Proved reserves:

           

Developed

      1,447              3,975              2,110              8,101               16,274              10,813       

Undeveloped

    -            -            -            -            -            -       
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total proved—December 31, 2012

      1,447              3,975              2,110               8,101               16,274              10,813       
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Standardized measure(1)

        $   68,953              $   188,728       
     

 

 

       

 

 

 

 

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(1)

Standardized measure of discounted future net cash flows as of December 31, 2012. 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, 2012 on a 90% basis were 2,110 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.

The above tables do not include any proved undeveloped reserve quantities as of December 31, 2012 because the underlying properties consist of mature producing properties that are essentially fully developed. Technical studies have not identified any drilling locations that meet the criteria of proved undeveloped reserves, nor has any future capital been committed for the development of proved undeveloped reserves on the underlying properties.

Proved reserves. 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. 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, 2012. 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, 2010 to December 31, 2012, 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 2012, revisions to previous estimates decreased proved reserves by a net amount of 17 MBOE. Included in these revisions were 0.2 Bcf of downward adjustments to natural gas, primarily due to lower gas prices of $3.07 per Mcf in reserve estimates at December 31, 2012, as compared to gas prices of $4.10 per Mcf at December 31, 2011 and 19 MBbl of upward adjustments to crude oil reserves, primarily due to increased estimates of future production resulting from recent workovers and well performance.

 

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Preparation of reserves estimates. Whiting has advised the Trust 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 issued by the Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Whiting’s current ownership in mineral interests and well production data are also subject to the aforementioned internal controls over financial reporting, and they are incorporated in the reserve database as well and verified to ensure their accuracy and completeness. Once the reserve database has been entirely updated with current information, and all relevant technical support material has been assembled, the Trust’s independent engineering firm Cawley, Gillespie & Associates, Inc. (“CG&A”) meets with Whiting’s technical personnel in Whiting’s Denver and Midland offices to review field performance. Following these reviews the reserve database is furnished to CG&A so that they can prepare their independent reserve estimates and final report. Access to Whiting’s reserve database is restricted to specific members of the reservoir engineering department.

CG&A is a Texas Registered Engineering Firm. The primary contact at CG&A is Mr. Robert Ravnaas, 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 39 years of experience, the majority of which has involved reservoir engineering and reserve estimation, holds a Bachelor’s degree in Petroleum Engineering from the University of Wyoming, holds an MBA from the University of Denver and is a registered Professional Engineer. He has also served on the national Board of Directors of the Society of Petroleum Evaluation Engineers.

As noted above, the current reserve report projects that 9.11 MMBOE attributable to the NPI will be produced from the underlying properties by June 30, 2015, which differs from the August 31, 2015 projected date in the December 31, 2011 reserve report. This change is primarily due to increased estimates of future production resulting from recent workovers and the completion of wells drilled in 2012. The projected time to produce the remaining reserves

 

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attributable to the Trust is therefore reduced. 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. In addition, the reserves and net revenues attributable to the NPI include only 90% of the reserves attributable to the underlying properties that are expected to be produced within 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 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, 2012. Undeveloped acreage is not significant.

 

     Number of    Total Acreage

Region

         Fields                Gross                Net      

Mid-Continent

         56                67,201                30,858        

Rocky Mountains

         61                73,467                28,016        

Permian Basin

         28                31,237                7,815      

Gulf Coast

         21                34,811                4,974      
  

 

  

 

  

 

Total

         166                  206,716                  71,663      
  

 

  

 

  

 

The following is a summary of the producing wells on the underlying properties as of December 31, 2012:

 

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

Oil

          275                173.2                2,112                84.1                2,387                257.3       

Natural gas

          71                49.0                623                61.7                694                110.7       
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

        346                222.2                2,735                145.8                3,081                368.0       
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

 

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well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. A productive well is an exploratory, development or extension well that is not a dry well. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves found. Whiting did not drill any exploratory wells on the underlying properties during the periods presented. There were three wells that were in the process of being drilled as of December 31, 2012.

 

    Year Ended December 31,  
    2012     2011     2010  
    Gross   Net     Gross   Net     Gross   Net  

Productive

           

Oil wells

          5                   0.5                      7                   1.0                      9                 2.5           

Natural gas wells

  3     -                 6     0.2              3     -           

Dry

  -     -                 2     0.5              1     0.1           
 

 

 

 

 

   

 

 

 

 

   

 

 

 

 

 

Total

  8     0.5              15      1.7              13     2.6           
 

 

 

 

 

   

 

 

 

 

   

 

 

 

 

 

Oil and Natural Gas Production

The table below shows total oil and gas production, average sales prices and average production costs attributable to underlying properties:

 

             Year Ended December 31,           
         2012              2011              2010      

Net production:

        

Oil production (MBbl)

     753         740         792   

Natural gas production (MMcf)

     2,705         2,778         3,156   

Total production (MBOE)

     1,204         1,203         1,318   

Average daily production (MBOE/d)

     3.3         3.3         3.6   

Magnolia field production:(1)

        

Oil production (MBbl)

     120         128         124   

Natural gas production (MMcf)

     167         165         166   

Total production (MBOE)

     147         156         152   

Average sales prices:

        

Oil (per Bbl)

   $ 79.33       $ 82.63       $ 66.58   

Natural gas (per Mcf)

   $ 2.86       $ 4.17       $ 4.37   

Production costs per BOE(2)

   $ 24.01       $ 20.11       $ 17.07   

 

(1)

Magnolia field was the only field that contained 15% or more of the total proved reserve volumes at December 31, 2012.

(2)

Production costs reported above exclude from lease operating expenses ad valorem taxes of $1.1 million ($0.94/BOE), $1.1 million ($0.88/BOE) and $1.0 million ($0.78/BOE) for the years ended December 31, 2012, 2011 and 2010, respectively.

 

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Producing wells the Trust has an interest in are part of 14 enhanced oil recovery waterflood projects, and aggregate production from such enhanced oil recovery fields averaged 687 BOE/d during 2012 or 21% of 2012 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.

Delivery Commitments

Neither the Trust nor the underlying properties are committed to deliver fixed quantities of oil or 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, 2012, approximately 65% of these properties were operated by Whiting. Based on annual 2012 production attributable to the underlying properties, approximately 63% of production was crude oil and natural gas liquids and 37% 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 decline over time.

Mid-Continent Region. The underlying properties in the Mid-Continent region are located in Arkansas, Oklahoma, Kansas and Michigan. These properties include 56 fields of which Whiting operates wells in 25 of these fields. There are two significant fields located in Arkansas. The Magnolia Smackover Pool Unit, the largest single field in the underlying properties, produces from the Smackover Lime. The second Arkansas field is the Stephens-Smart field, producing from the Buckrange and Travis Peak. The major fields and areas in Oklahoma are located in the Anadarko Basin and include Putnam Field, Mocane-Laverne Gas Area, Sho-Vel-Tum Field and Nobscot Northwest Field, which primarily produce from the Oswego, Hunton, Penn, Morrow, Red Fork and Cottage Grove zones. Case Field is the major Michigan field in the region and produces from the Silurian Niagaran zone. For the year ended December 31, 2012, the net production attributable to the underlying properties in the region was 479.7 MBOE or 1.3 MBOE/d.

Rocky Mountains Region. The underlying properties in the Rocky Mountains region are located in two distinct areas. The first, from which crude oil is primarily produced, includes the Williston Basin in North Dakota and Montana as well as the Bighorn and Powder River Basins of Wyoming, while the second, from which natural gas is primarily produced, includes southwest Wyoming, Colorado and Utah. These properties include 61 fields, and Whiting operates wells in 31 of these fields. The major North Dakota fields in this region include the Bell Field and the Fryburg Field that produce from Tyler sandstone; the Whiskey Joe, Teddy Roosevelt, Sherwood and Davis Creek Fields that produce from various intervals in the

 

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Madison; the Hiline Unit that produces from the Lodgepole; and the Big Dipper Field that produces from the Duperow and Red River zones. In Montana, the major fields include the Bainville Field and Palomino Fields that produce primarily from the Nisku zone, and the Oxbow Field that produces from the Nisku and Red River zones. The major Wyoming fields in this region include the Sage Creek Field in the Bighorn Basin that produces from the Tensleep and Madison zones and the Kiehl Field in the Powder River Basin, which produces from the Minnelusa formation and is under waterflood. The Ignacio Blanco Field is the major Colorado field in this region and produces from the Fruitland Coal zone. For the year ended December 31, 2012, the net production attributable to the underlying properties in the region was 425.3 MBOE or 1.2 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 include 28 fields, and Whiting operates wells in 9 of these fields. The major fields in this region include the Iatan East Howard Field, which produces from the San Andres, Glorieta and Clearfork zones; the Fullerton Field, which is unitized and produces from the Clearfork zone; and the Patricia Field, which produces from the Sprayberry and Fusselman zones. For the year ended December 31, 2012, the net production attributable to the underlying properties in the region was 178.1 MBOE or 0.5 MBOE/d.

Gulf Coast Region. The underlying properties in the Gulf Coast region are located in Texas, Louisiana, Mississippi and Alabama. These properties include 21 onshore fields, and Whiting operates wells in one of these fields. The major field in this region is the Mestena Grande Field located in Texas, which produces from the Queen City zone. For the year ended December 31, 2012, the net production attributable to the underlying properties in the region was 120.8 MBOE or 0.3 MBOE/d.

Abandonment and Sale of Underlying Properties

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 or eliminate the potential conflict of interest between Whiting and the Trust in determining whether a well is capable of producing in commercially paying quantities, Whiting has agreed to operate the underlying properties as a reasonably prudent operator in the same manner that it would operate if these properties were not burdened by the NPI, and Whiting has agreed to use commercially reasonable efforts to cause the other operators to operate these properties in the same manner. For the years ended December 31, 2012, 2011 and 2010, there were 9, 8 and 20 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 release the NPI associated with any lease that accounts for less than or equal to 0.25% of the

 

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total production from the underlying properties in the prior 12 months and provided that the NPI covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the Trust of $500,000. These releases will be made only in connection with a sale by Whiting of the relevant underlying properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such NPI. Any net sales proceeds paid to the Trust are distributable to Trust unitholders in the quarter in which they are received. During 2012, Whiting had no divestitures of Trust properties. Whiting includes all such proceeds from Trust property divestitures in its NPI distributions to the Trust.

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, express and implied, under oil and natural gas leases;

 

   

overriding royalties, production payments and similar interests and other burdens 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 the underlying properties or their title;

 

   

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.

 

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Whiting has informed the Trustee that Whiting believes the burdens and obligations affecting the 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.

Whiting acquired the underlying properties in various transactions that have occurred during its 28 year existence prior to the conveyance. At the time of its acquisitions of the underlying properties, Whiting undertook a title examination of these properties.

Net profits interests are non-operating, non-possessory interests carved out of the oil and natural gas leasehold estate, but some jurisdictions have not directly determined whether a 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 Trust, 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 that 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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PART 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 April 30, 2008 under the symbol “WHX.” Prior to April 30, 2008, there was no established public trading market for the Trust units. The high and low sales prices per unit for each quarter in 2012 and 2011 were as follows:

 

     For the Year Ended December 31,  
     2012     2011  
     High     Low     High     Low  

First quarter (January 1 through March 31)

   $     19.15          $     15.61      $     24.72          $     14.65       

Second quarter (April 1 through June 30)

   $ 18.69          $ 16.22      $ 18.17          $ 14.02       

Third quarter (July 1 through September 30)

   $ 18.20          $ 6.83      $ 18.25          $ 15.25       

Fourth quarter (October 1 through December 31)

   $ 7.98          $ 4.35      $ 18.85          $ 15.35       

At December 31, 2012, the 13,863,889 units outstanding were held by three 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 expenses 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 2012 and 2011 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 (dollars in thousands, except distributable income per unit).

 

2012 Quarterly
Distributions

  Net Cash Proceeds
(90% NPI)
    Estimated Trust
Expenses
    Montana State
Income Tax
Withholdings
    Distributable
Income per Unit
 

First quarter

  $                 10,247          $                 175          $                 70          $         0.721468       

Second quarter

    10,285            175            81            0.723387       

Third quarter

    9,845            245            49            0.688853       

Fourth quarter

    7,479            325            51            0.512336       
 

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $ 37,856          $ 920          $ 251          $ 2.646044       
 

 

 

   

 

 

   

 

 

   

 

 

 

 

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2011 Quarterly
Distributions

  Net Cash Proceeds
(90% NPI)
    Estimated Trust
Expenses
    Montana State
Income Tax
Withholdings
    Distributable
Income per Unit
 

First quarter

  $                 9,567          $                 250          $                 58          $         0.667847       

Second quarter

    10,313            150            59            0.728739       

Third quarter

    11,684            175            84            0.824101       

Fourth quarter

    10,369            175            62            0.730866       
 

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $ 41,933          $ 750          $ 263          $ 2.951553       
 

 

 

   

 

 

   

 

 

   

 

 

 

Subsequent to year end, on March 1, 2013, a distribution of $0.577618 per Trust unit was paid to Trust unitholders owning Trust units as of February 19, 2013. The distribution consisted of net cash proceeds of $8.0 million paid by Whiting to the Trust, which is inclusive of cash receipts totaling $1.2 million (90% of $1.4 million) for commodity derivative contracts settled for October through December 2012, less a provision of $100,000 for estimated Trust expenses and $65,755 for Montana state income tax withholdings.

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 2012.

Item 6. Selected Financial Data

The following table sets forth selected data for the Trust for the years ended December 31, 2012, 2011 and 2010 and as of December 31, 2012, 2011 and 2010 based on the Trust’s audited financial statements (dollars and shares in thousands, except distributable income per unit):

 

    Year Ended December 31,  
    2012     2011     2010  

Income from net profits interest

  $ 37,856          $ 41,933          $ 38,442       

Distributable income

  $ 36,685          $ 40,920          $ 37,422       

Distributable income per unit

  $     2.646044          $     2.951553          $     2.699295       

 

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    December 31,  
    2012     2011     2010  

Trust corpus

  $     31,055          $     46,593          $     61,999       

Total assets at year-end

  $ 31,282          $ 46,739          $ 62,144       

Trust units outstanding

    13,864            13,864            13,864       

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

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 was in turn subject to commodity hedge contracts through December 2012. 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 following table highlights these price trends by listing quarterly average NYMEX crude oil and natural gas prices for the periods indicated through September 30, 2012. The 2012 NPI distributions are mainly affected, however, by October 2011 through September 2012 oil prices and by September 2011 through August 2012 natural gas prices.

 

    2010     2011     2012  
    Q1     Q2     Q3     Q4     Q1     Q2     Q3     Q4     Q1     Q2     Q3  

Crude oil (per Bbl)

  $ 78.79      $ 77.99      $ 76.21      $ 85.18      $ 94.25      $ 102.55      $ 89.81      $ 94.02      $ 102.94      $ 93.51      $ 92.19   

Natural gas (per MMBtu)

  $ 5.30      $ 4.09      $ 4.39      $ 3.81      $ 4.10      $ 4.32      $ 4.20      $ 3.54      $ 2.72      $ 2.21      $ 2.81   

Although oil prices fell significantly after reaching highs in the third quarter of 2008, they have experienced a rebound in 2010, 2011 and 2012. Natural gas prices have likewise fallen significantly since their peak in the third quarter of 2008 but have remained low throughout 2009, 2010 and 2011. In addition, natural gas prices declined during the first half of 2012, but have begun to improve in recent months. The following table highlights the settled NYMEX prices for natural gas for January 2012 through March 2013:

 

    2012     2013  
    Jan.     Feb.     Mar.     Apr.     May     June     July     Aug.     Sept.     Oct.     Nov.     Dec.     Jan.     Feb.     Mar.  

Natural gas

(per MMBtu)

  $ 3.08      $ 2.68      $ 2.41      $ 2.19      $ 2.03      $ 2.42      $ 2.77      $ 3.01      $ 2.63      $ 3.06      $ 3.47      $ 3.71      $ 3.35      $ 3.23      $ 3.43   

 

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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; (ii) a reduction in the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties; and (iii) an extension of the length of time required to produce 9.11 MMBOE (8.20 MMBOE at the 90% NPI) due to some wells thereby reaching their economic limits sooner. Alternatively, higher oil and natural gas prices may potentially result in an increase in the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties. All costless collar hedge contracts Whiting entered into, and in turn conveyed to the Trust, terminated as of December 31, 2012, and no additional hedges are allowed to be placed on the Trust assets. Consequently, for production after December 31, 2012, there will be no cash settlement gains or losses on commodity derivatives, and the Trust will have increased exposure to oil and natural gas price volatility.

Trust termination. The NPI will terminate when 9.11 MMBOE have been produced and sold from the underlying properties (which amount is equivalent to 8.20 MMBOE attributable to the 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. As a result, the market price of the Trust units will decline to zero at termination of the Trust. As of December 31, 2012 on a cumulative accrual basis, 6.10 MMBOE (74%) of the Trust’s total 8.20 MMBOE have been produced and sold (of which proceeds from the sale of 263 MBOE, which is 90% of 292 MBOE, have been distributed to unitholders in the Trust’s March 1, 2013 distribution) and a cumulative reserve quantity of 0.02 MMBOE have been divested. For additional discussion relating to, and of the assumptions underlying, the estimated date when 9.11 MMBOE (8.20 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.

 

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Results of Trust Operations

The following is a summary of income from net profits interest received by the Trust for the years ended December 31, 2012, 2011 and 2010, consisting of the February, May, August and November distributions for each respective year (dollars in thousands, except per Bbl, per Mcf and per BOE amounts):

 

    Year Ended December 31,  
    2012     2011     2010  

Sales volumes:

     

Oil from underlying properties (MBbl)

    762(a)          760(b)          804(c)     

Natural gas from underlying properties (MMcf)

    2,805(a)          2,947(b)          3,335(c)     
 

 

 

   

 

 

   

 

 

 

Total production (MBOE)

    1,229             1,251             1,360        
 

 

 

 

Average sales prices:

     

Oil (per Bbl)

  $ 80.78             $80.16           $ 65.39        

Effect of oil hedges on average price (per Bbl) (d)

    -             -             0.25        
 

 

 

   

 

 

   

 

 

 

Oil net of hedging (per Bbl)

  $ 80.78           $ 80.16           $ 65.64        
 

 

 

 

Natural gas (per Mcf)

  $ 3.16           $ 4.12           $ 4.26        

Effect of natural gas hedges on average price (per Mcf) (d)

    2.12             1.51             1.23        
 

 

 

   

 

 

   

 

 

 

Natural gas net of hedging (per Mcf)

  $ 5.28           $ 5.63           $ 5.49        
 

 

 

 

Costs (per BOE):

     

Lease operating expenses

  $ 23.99           $ 20.44           $ 17.39        

Production taxes

  $ 3.90           $ 4.25           $ 3.47        

Revenues:

     

Oil sales

  $ 61,542(a)        $ 60,886(b)        $ 52,558(c)     

Natural gas sales

    8,877(a)          12,135(b)          14,193(c)     
 

 

 

   

 

 

   

 

 

 

Total revenues

  $ 70,419           $ 73,021           $ 66,751        
 

 

 

 

Costs:

     

Lease operating expenses

  $ 29,495           $ 25,569           $ 23,643        

Production taxes

    4,799             5,310             4,718        

Cash settlement gains received on commodity derivatives (d)

    (5,937)            (4,450)            (4,323)       
 

 

 

   

 

 

   

 

 

 

Total costs

  $ 28,357           $ 26,429           $ 24,038        
 

 

 

   

 

 

   

 

 

 

Net proceeds

  $ 42,062           $ 46,592           $ 42,713        

Net profits percentage

    90%          90%          90%     
 

 

 

   

 

 

   

 

 

 

Income from net profits interest

  $ 37,856           $ 41,933           $ 38,442        
 

 

 

 

 

(a)

Oil and gas sales volumes and related revenues for the year ended December 31, 2012 (consisting of Whiting’s February, May, August and November 2012 NPI distributions to the Trust) generally represent crude oil production from October 2011 through September 2012 and natural gas production from September 2011 through August 2012.

 

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(b)

Oil and gas sales volumes and related revenues for the year ended December 31, 2011 (consisting of Whiting’s 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.

(c)

Oil and gas sales volumes and related revenues for the year ended December 31, 2010 (consisting of Whiting’s February, May, August and November 2010 NPI distributions to the Trust) generally represent crude oil production from October 2009 through September 2010 and natural gas production from September 2009 through August 2010.

(d)

As discussed below, all hedges terminated as of December 31, 2012.

Comparison of Results of the Trust for the Years Ended December 31, 2012 and 2011

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 cash settlements on commodity derivatives as follows:

Revenues. Oil and natural gas revenues decreased $2.6 million or 4% in 2012 compared to 2011. Revenues are a function of oil and natural gas sales prices and production volumes sold. The decrease in revenue between periods was due to lower sales prices realized for natural gas in 2012 and lower natural gas production volumes, which effect was partially offset by higher sales prices realized for crude oil during 2012. The average price for gas before the effects of hedging decreased 23% between periods, while the average price for oil before the effects of hedging increased 1%. Gas sales volumes decreased 5% or 142 MMcf during 2012 as compared to 2011, while oil volumes remained consistent between periods. Gas volume decreases in 2012 were primarily related to normal field production decline. Partially offsetting this gas volume decline were 2012 production increases related to (i) the resolution of pressure issues at a gas pipeline sales point in Oklahoma which negatively impacted gas production during 2011, (ii) recovery from Mississippi River flooding which hampered gas production in Louisiana during the third quarter of 2011, and (iii) three recently drilled gas wells that came on line during the last twelve months. Oil sales volumes remained relatively consistent between periods primarily due to four recently drilled oil wells that came on line during the last twelve months, as well as workover activity that resulted in increased production. These positive effects on oil production were largely offset by normal field production decline. In the December 31, 2012 reserve report, natural gas production attributable to the underlying properties is estimated to decline at rates ranging from 11% to 13% annually from 2013 through the estimated June 30, 2015 NPI termination date, while oil production is estimated to decline at approximately 9% annually over this same time period.

 

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Lease Operating Expenses. Lease operating expenses (“LOE”) increased $3.9 million or 15% during 2012 compared to 2011. This increase in lease operating expenses during 2012 was primarily due to an increase of $3.8 million in the cost of oilfield goods and services, a $0.5 million increase in operating costs charged to wells that are not operated by Whiting, and $0.4 million in higher labor costs on Whiting-operated properties. These increases were partially offset by a $0.8 million decrease in plug and abandonment charges between periods. The increase in overall LOE coupled with the decrease in overall production volumes between periods resulted in an increase in LOE on a per BOE basis of 17%, from $20.44 in 2011 to $23.99 in 2012.

Production Taxes. Production taxes are typically calculated as a percentage of oil and gas revenues before the effects of hedging. Tax credits and exemptions allowed in the various taxing jurisdictions are generally utilized to their potential. Production taxes during 2012 decreased $0.5 million or 10% compared to 2011, and production taxes as a percent of oil and gas revenues also declined between periods, from 7.3% in 2011 to 6.8% in 2012. This decrease was primarily related to certain production tax refunds received in the third quarter of 2012.

Cash Settlements on Commodity Derivatives. In connection with Whiting’s conveyance of the net profits interest to the Trust, Whiting entered into certain costless collar hedge contracts in order to reduce the Trust’s exposure to commodity price volatility. If current market prices are lower than a collar’s price floor when the cash settlement amount is calculated, Whiting receives cash proceeds from the contract counterparty. Conversely, if current market prices are higher than a collar’s price ceiling when the cash settlement amount is calculated, Whiting is required to pay the contract counterparty.

Cash settlements relating to these hedges resulted in a gain of $5.9 million for the year ended December 31, 2012, which had the effect of increasing the average price of natural gas by $2.12 per Mcf for that period, and cash settlements relating to these hedges resulted in a gain of $4.5 million for the year ended December 31, 2011, which had the effect of increasing the average price of natural gas by $1.51 per Mcf for that period. As a result, the total net price of natural gas of $5.28 per Mcf and $5.63 per Mcf that the Trust received for 2012 and 2011, respectively, included premiums of 40% and 27%, respectively, related to the effects of hedging for those same periods. However, all hedges and their related pricing impacts terminated as of December 31, 2012, while the Trust’s oil and gas reserves are currently projected to terminate in June 2015 based on the Trust’s 2012 reserve report. Therefore, no commodity price hedges will be in effect beginning January 1, 2013 through Trust termination to reduce the Trust’s exposure to oil and natural gas price volatility.

General and Administrative Expenses. For the year ended December 31, 2012, the Trust’s general and administrative expenses increased by $0.1 million as compared to 2011 due to differences in timing as to when certain administrative invoices were received and paid by the

 

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Trustee. Certain invoices for annual services provided by auditors and tax consultants were paid during the year ended December 31, 2012, and these recurring invoices were not similarly paid during the same 2011 reporting period.

Distributable Income. For the year ended December 31, 2012, the Trust’s distributable income was $36.7 million and was based on income from net profits interest of $37.9 million, which has been reduced by Trust general and administrative costs of $0.8 million and Montana state income tax withholdings of $0.3 million, and adjusted for changes in Trust cash reserves. This compares to distributable income of $40.9 million during 2011, which was based on income from net profits interest of $41.9 million that has been reduced by $0.7 million for Trust administrative expenses and $0.3 million in Montana state income tax withholdings, and adjusted for changes in Trust cash reserves.

Comparison of Results of the Trust for the Years Ended December 31, 2011 and 2010

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 cash settlements on commodity derivatives as follows:

Revenues. Oil and natural gas revenues increased $6.3 million or 9% in 2011 compared to 2010. Revenues are a function of oil and natural gas sales prices and production volumes sold. The increase in revenue between periods was due to higher sales prices realized for crude oil in 2011, which effect was partially offset by lower sales prices realized for natural gas and lower oil and natural gas production volumes between periods. The average price for oil before the effects of hedging increased 23% between periods, while the average price for natural gas before the effects of hedging decreased 3%. Oil volumes decreased 5% or 44 MBOE, and gas volumes decreased 12% or 388 MMcf during 2011 as compared to 2010. Both of these volume decreases were primarily due to normal field production decline. In the December 31, 2012 reserve report, natural gas production attributable to the underlying properties is estimated to decline at rates ranging from 11% to 13% annually from 2013 through the estimated June 30, 2015 NPI termination date, while oil production is estimated to decline at approximately 9% annually over this same time period.

Lease Operating Expenses. Lease operating expenses increased $1.9 million or 8% during 2011 compared to 2010, primarily due to a $1.3 million increase in workover activity and a $0.8 million increase in operating costs charged to wells that are not operated by

 

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Whiting. These increases were partially offset by various cost declines amounting to $0.2 million that were generally associated with lower 2011 production levels. The increase in overall LOE coupled with the decrease in overall production volumes between periods resulted in an increase in LOE on a per BOE basis of 18%, from $17.39 in 2010 to $20.44 in 2011.

Production Taxes. Production taxes are typically calculated as a percentage of oil and gas revenues before the effects of hedging. Tax credits and exemptions allowed in the various taxing jurisdictions are generally utilized to their potential. Production taxes during 2011 increased $0.6 million or 13% compared to 2010, primarily due to higher oil sales between periods. Production taxes as a percent of oil and gas revenues for 2011 and 2010 remained relatively constant at 7.3% and 7.1%, respectively.

Cash Settlements on Commodity Derivatives. In connection with Whiting’s conveyance of the net profits interest to the Trust, Whiting entered into certain costless collar hedge contracts in order to reduce the Trust’s exposure to commodity price volatility. If current market prices are lower than a collar’s price floor when the cash settlement amount is calculated, Whiting receives cash proceeds from the contract counterparty. Conversely, if current market prices are higher than a collar’s price ceiling when the cash settlement amount is calculated, Whiting is required to pay the contract counterparty.

Cash settlements relating to these hedges resulted in a gain of $4.5 million for the year ended December 31, 2011, which had the effect of increasing the average price of natural gas by $1.51 per Mcf for that period, and cash settlements relating to these hedges resulted in a gain of $4.3 million for the year ended December 31, 2010, which had the effect of increasing average prices by $0.25 per Bbl of oil and $1.23 per Mcf of natural gas for that period. As a result, the total net price of natural gas of $5.63 per Mcf and $5.49 per Mcf that the Trust received for 2011 and 2010, respectively, included a premium of 27% and 22%, respectively, related to the effects of hedging for those same periods. However, all hedges and their related pricing impacts terminated as of December 31, 2012, while the Trust’s oil and gas reserves are currently projected to terminate in June 2015 based on the Trust’s 2012 reserve report. Therefore, no commodity price hedges will be in effect beginning January 1, 2013 through Trust termination to reduce the Trust’s exposure to oil and natural gas price volatility.

General and Administrative Expenses. For the year ended December 31, 2011, the Trust’s general and administrative expenses decreased by $0.1 million as compared to 2010 due to differences in timing as to when certain administrative invoices were received and paid by the Trustee.

Distributable Income. For the year ended December 31, 2011, the Trust’s distributable income was $40.9 million and was based on income from net profits interest of $41.9 million, which has been reduced by Trust general and administrative costs of $0.7 million and Montana state income tax withholdings of $0.3 million, and adjusted for changes in Trust cash reserves. This compares to distributable income of $37.4 million during 2010, which was based on income

 

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from net profits interest of $38.4 million that has been reduced by $0.9 million of Trust administrative expenses and $0.2 million in Montana state income tax withholdings, and adjusted for changes in Trust cash reserves.

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 listed 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”.

Although capital expenditures for the testing, drilling, completion, equipping, plugging back or recompletion of any well that is a part of the underlying properties cannot be deducted from gross proceeds pursuant to the terms of the conveyance agreement, Whiting incurred capital expenditures of $6.8 million on the underlying properties during 2012, compared to $1.8 million in 2011 and $1.0 million in 2010. Such expenditures were not deducted from gross proceeds or Trust distributions, but they may have the effect of ultimately accelerating the receipt of NPI net proceeds and thereby benefiting the Trust unitholders by accelerating their return on investment. The Trust cannot provide any assurance that this will continue to occur or that future capital expenditures will be consistent with historical levels.

On February 8, 2011, Whiting established a $1.0 million letter of credit for the Trustee in order to provide a mechanism for the Trustee 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.

 

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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.

Contractual Obligations

The following table summarizes the Trust’s obligations and commitments as of December 31, 2012 to make future payments during the specified time periods:

 

    Payments Due by Period  

Contractual Obligations

  Total     2013     2014     2015(d)  

Delaware Trustee fees (a)

  $ 10,500          $ 3,500          $ 3,500          $ 3,500       

Trustee administrative service fees (b)

    400,000            160,000            160,000            80,000       

Whiting administrative service fees (c)

    500,000            200,000            200,000            100,000       
 

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $  910,500          $  363,500          $  363,500          $  183,500       
 

 

 

   

 

 

   

 

 

   

 

 

 

 

(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 $160,000 per year.

(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 2015 period represents obligations through the June 2015 estimated Trust termination date, based on the Trust’s 2012 reserve report, although actual amounts paid may differ from these estimates.

New Accounting Pronouncements

There were no accounting pronouncements issued during the year ended December 31, 2012 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.

 

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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.

 

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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 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. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to produce from higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on future economic and operational conditions.

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 2012, however, the NPI was subject to commodity hedge contracts in the form of costless collars entered into by Whiting, which reduced the NPI’s exposure to commodity price volatility. The revenues derived from the underlying properties depend substantially on prevailing crude oil, natural gas and natural gas liquid prices. As a result, commodity prices also affect the amount of cash flow available for distribution to the Trust unitholders. Lower prices may also reduce the amount of oil, natural gas and natural gas liquids that Whiting can economically produce. Whiting sells the oil, natural gas and natural gas liquid production from the underlying properties under floating market price contracts each month. Whiting entered into certain hedge contracts through December 31, 2012 to manage the exposure to crude oil

 

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and natural gas price volatility, which is associated with revenues generated from the underlying properties, and to achieve more predictable cash flows. The hedge contracts consisted of costless collar arrangements placed with a single trading counterparty, JPMorgan Chase Bank National Association and were in place during the 2012, 2011 and 2010 periods presented in this Annual Report on Form 10-K. However, all hedging contracts terminated as of December 31, 2012. No additional hedges are allowed to be placed on Trust assets, nor can the Trust 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. Natural gas costless collar arrangements settle based on the closing settlement price on the second to last scheduled trading day of the month prior to delivery. 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. The amount received by Whiting from the counterparty upon settlements of the hedge contracts reduced the operating expenses related to the underlying properties when calculating net proceeds. Commodity derivative contracts that settled from October through December 2012 provided cash receipts of $1.2 million (90% of $1.4 million) which were included in the March 1, 2013 distribution to Trust unitholders. For a discussion of the March 1, 2013 distribution, see Note 8 to the Financial Statements included in this Annual Report on Form 10-K.

 

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Item 8. Financial Statements and Supplementary Data

Index to Whiting USA Trust I Financial Statements

(Modified Cash Basis)

 

Report of Independent Registered Public Accounting Firm

     69   

Statements of Assets, Liabilities and Trust Corpus as of December 31, 2012 and 2011

     70   

Statements of Distributable Income for the Years Ended December 31, 2012, 2011 and 2010

     70   

Statements of Changes in Trust Corpus for the Years Ended December 31, 2012, 2011 and 2010

     71   

Notes to Financial Statements

     72   

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Trustee and Unit Holders of

Whiting USA Trust I

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 I (the “Trust”) as of December 31, 2012 and 2011, and the related statements of distributable income and changes in trust corpus - modified cash basis for the years ended December 31, 2012, 2011, and 2010. These financial statements are the responsibility of the Trustee. 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 financial 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 I as of December 31, 2012 and 2011, and its distributable income and changes in trust corpus for the years ended December 31, 2012, 2011, and 2010, 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, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 15, 2013 expressed an unqualified opinion on the Trust’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Austin, Texas

March 15, 2013

 

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WHITING USA TRUST I

Statements of Assets, Liabilities and Trust Corpus

(In thousands, except unit data)

 

     December 31,  
     2012     2011  

ASSETS

    

Cash and short-term investments

   $ 227            $ 146         

Investment in net profits interest, net

     31,055              46,593         
  

 

 

   

 

 

 

Total assets

   $ 31,282            $ 46,739         
  

 

 

   

 

 

 

LIABILITIES AND TRUST CORPUS

    

Reserve for Trust expenses

   $ 227            $ 146         

Trust corpus (13,863,889 Trust units issued and outstanding)

     31,055              46,593         
  

 

 

   

 

 

 

Total liabilities and Trust corpus

   $     31,282            $     46,739         
  

 

 

   

 

 

 

Statements of Distributable Income

(In thousands, except distributable income per unit data)

 

     Year Ended December 31,  
     2012      2011      2010  

Income from net profits interest

   $ 37,856            $ 41,933            $ 38,442        

General and administrative expenses

     (839)             (749)             (892)       

Cash reserves used (withheld) for current Trust expenses

     (81)             (1)             91       

State income tax withholding

     (251)             (263)             (219)       
  

 

 

    

 

 

    

 

 

 

Distributable income

   $ 36,685            $ 40,920            $ 37,422        
  

 

 

    

 

 

    

 

 

 

Distributable income per unit

   $   2.646044            $   2.951553            $   2.699295        
  

 

 

    

 

 

    

 

 

 

 

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Statements of Changes in Trust Corpus

(In thousands)

 

     Year Ended December 31,  
     2012      2011      2010  

Trust corpus, beginning of period

   $ 46,593            $ 61,999            $ 79,346        

Distributable income

     36,685              40,920              37,422        

Distributions to unitholders

     (36,685)             (40,920)             (37,422)       

Amortization of investment in net profits interest

     (15,538)             (15,406)             (17,347)       
  

 

 

    

 

 

    

 

 

 

Trust corpus, end of period

   $         31,055            $         46,593            $         61,999        
  

 

 

    

 

 

    

 

 

 

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

 

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WHITING USA TRUST I

NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS

1. ORGANIZATION OF THE TRUST

Formation of the Trust — Whiting USA Trust I (the “Trust”) is a statutory trust formed in October 2007 under the Delaware Statutory Trust Act, pursuant to a trust agreement (the “Trust agreement”) among Whiting Oil and Gas Corporation and Equity Oil Company, as trustors, The Bank of New York Trust Company, N.A., as Trustee (subsequently renamed The Bank of New York Mellon Trust Company, N.A., and hereinafter referred to as “Trustee”) and Wilmington Trust Company as Delaware Trustee (the “Delaware Trustee”). The initial capitalization of the Trust estate was funded by Whiting Petroleum Corporation (“Whiting”) in November 2007. Effective September 30, 2009, Equity Oil Company merged into Whiting Oil and Gas Corporation (“Whiting Oil and Gas”) with Whiting Oil and Gas as the surviving corporation. Whiting Oil and Gas, as referred to herein, is a subsidiary of Whiting and the successor to Equity Oil Company.

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 to the Trust from Whiting Oil and Gas. The term NPI is an interest in certain of Whiting Oil and Gas’ properties located in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions (the “underlying properties”). The NPI is the only asset of the Trust, other than cash reserves held for Trust expenses. As of December 31, 2012, these oil and gas properties included interests in 3,081 gross (368.0 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 when 9.11 MMBOE have been produced and sold from the underlying properties (which amount is the equivalent of 8.20 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the 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, 2012, on a cumulative accrual basis 6.10 MMBOE (74%) of the Trust’s total 8.20 MMBOE have been produced and sold and a cumulative 0.02 MMBOE have been sold in divestitures. The remaining reserve quantities are projected to be produced by June 30, 2015, based on the reserve report for the underlying properties as of December 31, 2012.

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 that the terms of the loan are similar to the terms it would grant to a similarly situated commercial

 

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customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself and make other short-term investments with the funds distributed to the Trust.

Initial Issuance of Trust Units and Net Profits Interest Conveyance — In April 2008, the Trust issued 13,863,889 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 11,677,500 Trust units to the public. Whiting retained, and has continued to retain, an ownership in 2,186,389 Trust units, or 15.8% of the total Trust units issued and outstanding.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Term Net Profits Interest — The Trust uses the modified cash basis of accounting to report Trust receipts from the term NPI and payments of expenses incurred. The actual cash distributions 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, production and property taxes, payments made by Whiting to the hedge counterparty upon settlements of hedge contracts, maintenance expenses, post-production costs including plugging and abandonment, and producing overhead, exceed hedge payments received by Whiting under hedge contracts and other non-production revenue) of the underlying properties 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 AccountingThe 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

 

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  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. As of December 31, 2012 and 2011, no such impairment had occurred. 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.

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

Concentration of Credit RiskThe 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 natural gas sales for the years ended December 31, 2012, 2011 and 2010:

 

         2012           2011           2010    

Lion Oil Company

   17%   16%   14%

Enterprise South Texas

   15%   15%     8%

Plains Marketing

   11%   9%     8%

The loss of one or all of these purchasers does not present a material risk because there is significant competition among purchasers of crude oil and natural gas in the areas of the underlying properties, and if they were to lose one or more of their largest purchasers, several entities could purchase crude oil and natural gas produced from the underlying properties with little or no interruption to their business.

 

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Use of EstimatesThe 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 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 PronouncementsThere were no accounting pronouncements issued during the year ended December 31, 2012 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 13,863,889 Trust units. The investment in net profits interest was recorded at the historical cost of Whiting on April 30, 2008, the date of conveyance, and was determined to be $123.6 million, of which $111.2 million (90% of the NPI) was attributed to the Trust. As of December 31, 2012 and 2011, accumulated amortization of the investment in net profits interest was $80.2 million and $64.6 million, respectively.

4. INCOME FROM NET PROFITS INTEREST

The Trust received income from net profits interest as follows (dollars in thousands):

 

    Year Ended December 31,      
    2012          2011          2010      

Revenues:

             

Oil sales

  $  61,542    (a)       $  60,886         (b)      $  52,558        (c)

Natural gas sales

    8,877    (a)         12,135         (b)      14,193        (c)
 

 

 

      

 

 

      

 

 

   

Total revenues

    70,419            73,021              66,751       
 

 

 

      

 

 

      

 

 

   

Costs:

             

Lease operating expenses

    29,495            25,569              23,643       

Production taxes

    4,799            5,310              4,718       

Cash settlement gains received on commodity derivatives(d)

    (5,937)           (4,450)             (4,323)      
 

 

 

      

 

 

      

 

 

   

Total costs

    28,357            26,429              24,038       
 

 

 

      

 

 

      

 

 

   

Net proceeds

    42,062            46,592              42,713       

Net profits percentage

    90        %      90         %      90        %
 

 

 

      

 

 

      

 

 

   

Income from net profits interest

  $       37,856          $       41,933            $       38,442       
 

 

 

      

 

 

      

 

 

   

 

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  (a)

Oil and gas sales volumes and related revenues for the year ended December 31, 2012 (consisting of Whiting’s February, May, August and November 2012 NPI distributions to the Trust) generally represent crude oil production from October 2011 through September 2012 and natural gas production from September 2011 through August 2012.

  (b)

Oil and gas sales volumes and related revenues for the year ended December 31, 2011 (consisting of Whiting’s 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.

  (c)

Oil and gas sales volumes and related revenues for the year ended December 31, 2010 (consisting of Whiting’s February, May, August and November 2010 NPI distributions to the Trust) generally represent crude oil production from October 2009 through September 2010 and natural gas production from September 2009 through August 2010.

  (d)

All hedges terminated as of December 31, 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 $0.3 million, $0.3 million and $0.2 million related to Montana state income taxes for the years ended December 31, 2012, 2011 and 2010, respectively. For North Dakota, Oklahoma, Arkansas, Michigan, New Mexico, Alabama, Louisiana, Colorado, Kansas, Utah and Mississippi, 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.

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.

 

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7. RELATED PARTY TRANSACTIONS

Capital ExpendituresDuring the years ended December 31, 2012, 2011 and 2010, Whiting incurred $6.8 million, $1.8 million and $1.0 million, respectively, of capital expenditures on the underlying properties. These capital expenditures are the costs net to Whiting’s interest in the wells and which are related to the drilling and completing of oil and gas wells, capital workovers, facility upgrades and well recompletions that are performed to secure production from new horizons. Pursuant to the terms of the conveyance agreement, such expenditures were not deducted from gross proceeds or the Trust distributions, but they may have the effect of ultimately accelerating the receipt of NPI net proceeds and thereby benefiting the Trust unitholders by accelerating their return on investment. The Trust cannot provide any assurance that this will continue to occur or that future capital expenditures will be consistent with historical levels.

Operating OverheadPursuant to the terms of the applicable joint operating agreements, Whiting deducts from the 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, 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, 2012, 2011 and 2010 (in thousands, except per well data):

 

   

2012

    

2011

    

2010

 

Total overhead charges

  $     1,739       $     1,701       $     1,788   

Overhead charge per month per active operated well

  $ 419       $ 407       $ 415   

Administrative Services FeeUnder 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 the Trust’s statements of distributable income for the years ended December 31, 2012, 2011 and 2010 each include $200,000 for quarterly administrative fees paid to Whiting.

Trustee Administrative FeeUnder the terms of the Trust agreement, the Trust pays an annual administrative fee to the Trustee of $160,000, paid in four quarterly installments of $40,000 each and is billed in arrears. General and administrative expenses in the Trust’s statements of distributable income for the years ended December 31, 2012, 2011 and 2010 each include $160,000 for quarterly administrative fees paid to the Trustee.

 

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Letter of Credit — On February 8, 2011, 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.

8. SUBSEQUENT EVENT

On March 1, 2013, a distribution of $0.577618 per Trust unit was paid to Trust unitholders owning Trust units as of February 19, 2013. The distribution consisted of net cash proceeds of $8.0 million paid by Whiting to the Trust, which is inclusive of cash receipts totaling $1.2 million (90% of $1.4 million) for commodity derivative contracts settled from October through December 2012, less a provision of $100,000 for estimated Trust expenses and $65,755 for Montana state income tax withholdings.

9. 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, 2012, 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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The following is a summary of the changes in quantities of proved oil and gas reserves attributable to the Trust for the years ended December 31, 2010, 2011 and 2012:

 

    Oil
  (MBbl)  
    Natural
Gas
  (MMcf)  
      MBOE    

Balance — January 1, 2010 (1)

    3,604           10,976           5,433      

Revisions to previous estimates

    (201)          1,397           32      

Extensions and discoveries

    42           19           45      

Divestitures (2)

    -           (4)          (1)     

Production

    (713)          (2,841)          (1,186)     
 

 

 

   

 

 

   

 

 

 

Balance — December 31, 2010 (1)

    2,732           9,547           4,323      

Revisions to previous estimates

    8           (481)          (71)     

Extensions and discoveries

    17           36            23      

Divestitures

    -           -           -      

Production

    (666)          (2,500)          (1,083)     
 

 

 

   

 

 

   

 

 

 

Balance — December 31, 2011(1)

    2,091           6,602           3,192      

Revisions to previous estimates

    19           (214)          (17)     

Extensions and discoveries

    15           21           19      

Divestitures

    -           -           -      

Production

    (678)          (2,434)          (1,084)     
 

 

 

   

 

 

   

 

 

 

Balance — December 31, 2012(1)

          1,447                 3,975                 2,110      
 

 

 

   

 

 

   

 

 

 

Proved developed reserves(3):

     

January 1, 2010

    3,604           10,976           5,433      
 

 

 

   

 

 

   

 

 

 

December 31, 2010

    2,732           9,547           4,323      
 

 

 

   

 

 

   

 

 

 

December 31, 2011

    2,091           6,602           3,192      
 

 

 

   

 

 

   

 

 

 

December 31, 2012

    1,447           3,975           2,110      
 

 

 

   

 

 

   

 

 

 

 

  (1)

Reserves related to the underlying properties on a 100% full economic life basis as of January 1, 2010 and as of December 31, 2010, 2011 and 2012 were 9.3 MMBOE, 12.6 MMBOE, 13.0 MMBOE and 10.8 MMBOE, respectively. The oil and gas reserve quantities presented in the tables above are on a 90% NPI Trust life basis.

  (2)

During 2010 Whiting received sale proceeds of $3,172 in exchange for its divestiture of Trust properties that held 1 MBOE of proved reserves. Whiting includes all such proceeds from Trust property divestitures in its NPI distributions to the Trust.

  (3)

These tables do not include quantities of proved undeveloped reserve as of January 1, 2010 or as of December 31, 2010, 2011 and 2012 because the underlying properties consist of mature producing properties that are generally fully developed. Technical studies have not identified any drilling locations that meet the criteria of proved undeveloped reserves, nor has any future capital been committed for the development of proved undeveloped reserves on the underlying properties.

 

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

 

   

Revisions to previous estimates. In 2012, revisions to previous estimates decreased proved reserves by a net amount of 17 MBOE. Included in these revisions were 0.2 Bcf of downward adjustments to natural gas, primarily due to lower gas prices of $3.07 per Mcf in reserve estimates at December 31, 2012, as compared to gas prices of $4.10 per Mcf at December 31, 2011. This downward revision in natural gas reserves was partially offset by 19 MBbl of upward adjustments to crude oil reserves primarily due to increased estimates of future production resulting from recent workovers and well performance.

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 71 MBOE. Included in these revisions were 0.5 Bcf of downward adjustments to natural gas, primarily due to lower gas prices of $4.10 per Mcf in reserve estimates at December 31, 2011, as compared to gas prices of $4.17 per Mcf at December 31, 2010. This downward revision in natural gas reserves was partially offset by 8 MBbl of upward adjustments to crude oil reserves primarily due to higher oil prices of $84.19 per Bbl in reserve estimates at December 31, 2011, as compared to $68.77 per Bbl of oil at December 31, 2010.

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

 

   

Revisions to previous estimates. In 2010, revisions to previous estimates increased proved reserves by a net amount of 32 MBOE. Included in these revisions were 1.4 Bcf of upward adjustments to natural gas primarily due to higher gas prices of $4.17 per Mcf in reserve estimates at December 31, 2010, as compared to gas prices of $3.15 per Mcf at December 31, 2009. This upward revision in natural gas was almost entirely offset, however, by 201 MBbl of downward adjustments to crude oil reserves. Crude oil reserves declined in 2010 primarily due to adjustments to production accruals, which decreases were partially offset by higher oil prices of $68.77 per Bbl in reserve estimates at December 31, 2010, as compared to $51.58 per Bbl of oil at December 31, 2009.

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 ActivitiesOil and Gas. Future cash inflows as of December 31, 2012, 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 period ended December 31, 2012, 2011 and 2010) to estimated future production. Future production and development costs are computed by

 

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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 relating to proved oil and gas reserves attributable to the Trust is as follows (dollars in thousands):

 

    December 31,  
    2012     2011     2010  

Future cash inflows

  $   131,507         $   203,101         $   227,682      

Future production costs

    (54,502)          (75,757)          (98,372)     

Future development costs

    —           —           —      
 

 

 

   

 

 

   

 

 

 

Future net cash flows

    77,005           127,344           129,310      

10% annual discount for estimated timing of cash flows

    (8,052)          (18,614)          (23,603)     
 

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows(1)

  $ 68,953         $ 108,730         $ 105,707      
 

 

 

   

 

 

   

 

 

 

 

  (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 (dollars in thousands):

 

     December 31,  
     2012     2011     2010  

Beginning of year

   $   108,730         $   105,707         $   77,551      

Sale of oil and gas produced, net of production costs

     (29,495)          (37,563)          (34,352)     

Sale of minerals in place

     —           —           3      

Net changes in prices and production costs

     (21,231)          31,579           52,759      

Extensions and discoveries less related costs

     724           749           1,164      

Changes in estimated future development costs, net

     —           —           —      

Revisions of previous quantity estimates

     (648)          (2,313)          827      

Accretion of discount

     10,873           10,571           7,755      
  

 

 

   

 

 

   

 

 

 

End of year

   $ 68,953         $ 108,730         $ 105,707      
  

 

 

   

 

 

   

 

 

 

 

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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, 2012, 2011 and 2010 as follows:

 

     2012      2011      2010  

Oil (per Bbl)

   $     82.44       $     84.19       $     68.77   

Gas (per Mcf)

   $ 3.07       $ 4.10       $ 4.17   

10. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

 

    Three Months Ended (1)  

Year Ended December 31, 2012

  March 31     June 30     September 30     December 31     Total  

Income from net profits interest

  $ 10,247        $ 10,285        $ 9,845        $ 7,479        $ 37,856     

Distributable income

  $ 10,003        $ 10,029        $ 9,550        $ 7,103        $ 36,685     

Distributions per unit

  $  0.721468        $  0.723387        $  0.688853        $  0.512336        $  2.646044     

Year Ended December 31, 2011

         

Income from net profits interest

  $ 9,567        $ 10,313        $ 11,684        $ 10,369        $ 41,933     

Distributable income

  $ 9,259        $ 10,103        $ 11,425        $ 10,133        $ 40,920     

Distributions per unit

  $ 0.667847        $ 0.728739        $ 0.824101        $ 0.730866        $ 2.951553     

 

  (1)

Dollars in thousands, except for distributions per unit.

******

 

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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, 2012, 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

 

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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 based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control—Integrated Framework, the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2012.

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 15, 2013

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Trustee and Unit Holders of

Whiting USA Trust I

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 I (the “Trust”) as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework 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

 

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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, 2012, based on the criteria established in Internal Control — Integrated Framework 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, 2012 of the Trust and our report dated March 15, 2013 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 15, 2013

 

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Item 9B. Other Information

None.

PART III

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 2012.

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, 2012 the Trustee received administrative fees from the Trust in the amount of $160,000. 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.

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

 

(a)

Security Ownership of Certain Beneficial Owners.

Based on filings with the SEC, the Trustee is not aware of any holders of 5% or more of the units except as set forth below. The following information has been obtained from filings with the SEC on Schedule 13G.

 

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Beneficial Owner

   Trust Units
Beneficially
      Owned      
     Percent of
       Class      
 

Whiting Petroleum Corporation

1700 Broadway, Suite 2300

Denver, CO 80290-2300

     2,186,389         15.8

 

(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

On February 8, 2011, Whiting established a $1.0 million letter of credit for the Trustee in order to provide a mechanism for the Trustee to pay the operating expenses of the Trust in the unlikely event that Whiting should fail to fund the Trust in the future. 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.

Capital Expenditures

During the year ended December 31, 2012, Whiting incurred capital expenditures of $6.8 million on the underlying properties. These capital expenditures are the costs net to Whiting’s interest in the wells and which are related to the drilling and completing of oil and gas wells, capital workovers, facility upgrades and well recompletions that are performed to secure production from new horizons. Pursuant to the conveyance agreement, such expenditures were not deducted from gross proceeds or the distributions in 2012 but may have the effect of ultimately accelerating the receipt of NPI net proceeds and thereby benefiting the Trust unitholders by accelerating their return on investment. The Trust cannot provide any assurance that this will continue to occur or that future capital expenditures will be consistent with historical levels.

Operating Overhead

Pursuant to the terms of the applicable operating agreements, Whiting deducts from the gross proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally, for those underlying properties for which Whiting is

 

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the operator but for which there is no operating agreement, Whiting deducts from the gross proceeds an overhead fee calculated in the same manner Whiting allocates overhead to other similarly owned properties, as is customary in the oil and gas industry. The operating overhead activities include various engineering, legal, and administrative functions. For the year ended December 31, 2012, the Trust’s portion of the monthly charge totaled $1.7 million and averaged $419 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 the Trust’s statements of distributable income for the year ended December 31, 2012 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 $160,000, paid in four quarterly installments of $40,000 each and is billed in arrears. General and administrative expenses in the Trust’s statements of distributable income for the year ended December 31, 2012 include $160,000 for quarterly administrative fees paid to the Trustee.

Registration Rights

The Trust entered into a registration rights agreement with Whiting in connection with Whiting’s conveyance to the Trust of the net profits interest. In the registration rights agreement, the Trust agreed, for the benefit of Whiting and any transferee of its Trust units (each, a “holder”), to register the Trust units it holds. Specifically, the Trust agreed:

 

   

to use its reasonable best efforts to file a registration statement, including, if so requested, a shelf registration statement, with the SEC as promptly as practicable following receipt of a notice requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable Trust units;

 

   

to use its reasonable best efforts to cause the registration statement or shelf registration statement to be declared effective under the Securities Act as promptly as practicable after the filing thereof; and notice requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable Trust units;

 

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

 

   

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

 

   

have been sold in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee of the Trust units.

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

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

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, 2013. During fiscal 2012 and 2011, 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, 2012 and 2011 by Deloitte (dollars in thousands):

 

           2012                  2011        

Audit fees (1)

   $ 190         $ 190     

Audit-related fees

     -           -     

Tax fees

     -           -     

All other fees

     -           -     
  

 

 

    

 

 

 

Total fees

   $       190         $       190     
  

 

 

    

 

 

 

 

(1)

Fees for audit services in 2012 and 2011 consisted of the audit of the Trust’s annual financial statements and reviews of the Trust’s quarterly financial statements.

 

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)(1) Financial Statements

Refer to the Index of Whiting USA Trust I 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 I

By:  

 

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.

By:  

 

/s/ MIKE ULRICH

 

Mike Ulrich

Vice President

March 15, 2013

The Registrant, Whiting USA Trust I, 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, SUITE 100    306 WEST SEVENTH STREET, SUITE 302    1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1707    FORT WORTH, TEXAS 76102-4987    HOUSTON, TEXAS 77002-5008
512-249-7000    817-336-2461    713-651-9944

January 11, 2013

Whiting USA Trust I

1700 Broadway, Suite 2300

Denver, Colorado 80290-2300

 

  Re:   

Evaluation Summary – SEC Price

        

Whiting USA Trust I Underlying
Properties

Proved Producing Reserves

Certain Properties Located in Various
States

As of December 31, 2012

    

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

Gentlemen:

As requested, we are submitting our estimates of proved producing reserves and forecasts of economics attributable to the underlying properties, from which a net profits interest has been formed and conveyed by Whiting Petroleum Corporation to the Whiting USA Trust I. These certain oil and gas properties are located in North Dakota, Texas, Oklahoma, Arkansas, Montana, Wyoming, Michigan, New Mexico, Alabama, Louisiana, Colorado, Kansas, Utah and Mississippi. Also included in the table below are the proved reserves attributable to the same underlying properties estimated to be produced by June 30, 2015, which is the estimated date of termination for Whiting USA Trust I. This report, completed January 11, 2013 covers 100% of the proved producing reserves estimated for Whiting USA Trust I. 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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          Proved Developed Producing  
       

Underlying
Properties

Full Economic Life

    Underlying Properties
Reserves Estimated to be Produced
By June 30, 2015
 
   

 

 

 

Net Reserves

     

Oil

    -   Mbbl     7,799.6        1,473.8   

Gas

    -   MMcf     16,273.9        4,416.8   

NGL

    -   Mbbl     301.5        134.1   

Equivalent*

    -   Mbbl     10,813.4        2,344.1   

Revenue

     

Oil

    -   M$     672,464.9        127,302.8   

Gas

    -   M$     50,533.5        13,555.7   

NGL

    -   M$     12,817.4        5,259.9   

Severance Taxes

 

  -   M$

    54,927.6        11,404.1   

Ad Valorem Taxes

 

  -   M$

    9,452.0        1,795.0   

Operating Expenses

 

  -   M$

    328,260.3        47,358.7   

Investments

 

  -   M$

    0.0        0.0   

Net Operating Income

 

  -   M$

    343,175.8        85,560.5   

Discounted @ 10%

    -   M$     188,728.4        76,614.6   

 

 

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

The discounted cash flow value shown in the previous table 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 $94.71 per bbl and $2.76 per MMBtu, respectively, were adjusted individually to WTI posted pricing at $91.32 per bbl and Houston Ship Channel pricing at $2.71 per MMBtu, as of December 31, 2012. 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 producing reserves for the underlying properties full economic life were $86.22 per bbl of oil, $42.52 per bbl of natural gas liquids and $3.11 per mcf of natural gas. For the proved producing reserves of the underlying properties estimated to be produced by June 30, 2015, the average adjusted prices were $86.38 per bbl of oil, $39.22 per bbl of natural gas liquids and $3.07 per mcf of natural gas.


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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 Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined on 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.

Miscellaneous

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

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


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

 

Yours very truly,

/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 or Fiscal years/months commencing on effective date.
(2) (3) (4)    Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.
(5) (6) (7)    Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.
(8)    Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
(9)    Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
(10)    Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
(12)    Revenue derived from oil sales -- column (5) times column (8).
(13)    Revenue derived from gas sales -- column (6) times column (9).
(14)    Revenue derived from NGL sales -- column (7) times column (10).
(15)    Revenue derived from other sources.
(16)    Revenue derived from hedge positions.
(17)    Total Revenue – sum of column (12) through column (16).
(18)    Production-Severance taxes deducted from gross oil and NGL revenue.
(19)    Production-Severance taxes deducted from gross gas revenue.
(20)    Revenue after taxes – column (17) less column (18) and column (19).
(22)    Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS.
(23)    Ad Valorem taxes.
(24)    Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
(25)    3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
(26)    Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.

 

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(27)    Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
(28) (29)    Future Net Cash Flow is column (18) less the total of column (19), column (22), column (24), column (25), column (26) and column (27). The data in column (28) are accumulated in column (29). Federal income taxes have not been considered.
(30)    Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.
MISCELLANEOUS
Input Data   

•      Evaluation parameters such as rates, tax percentages, and expenses are shown below columns (21-26).

Interests   

•      Initial and final expense and revenue interests are shown below columns (27-28).

DCF Profile   

•      The cash flow discounted at six different rates are shown at the bottom of columns (29-30). Interest has been compounded monthly.

Life   

•      The economic life of the appraised property is noted in the lower right-hand corner of the table.

Footnotes   

•      Well ID information or other pertinent comments may be shown in the lower left-hand footnotes.

 

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APPENDIX

Methods Employed in the Estimation of Reserves

 

 

 

 

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

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

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

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

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

 

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

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

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

 

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APPENDIX

Reserve Definitions and Classifications

 

 

 

 

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

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

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

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

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

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

“(v)        Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the

 

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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

“(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.

 

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“(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.

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

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

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

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

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

 

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“(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

 

9601 AMBERGLEN BLVD., SUITE 117

   306 WEST SEVENTH STREET, SUITE 302    1000 LOUISIANA STREET, SUITE 625

AUSTIN, TEXAS 78729-1106

   FORT WORTH, TEXAS 76102-4987    HOUSTON, TEXAS 77002-5008

512-249-7000

   817-336-2461    713-651-9944

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.


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INDEX TO EXHIBITS

 

Exhibit
Number

  

Description

3.1*

  

Certificate of Trust of Whiting USA Trust I [Incorporated herein by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (Registration No. 333-147543)].

3.2*

  

Amended and Restated Trust Agreement, dated April 30, 2008, among Whiting Oil and Gas Corporation, Equity Oil Company (subsequently merged into Whiting Oil and Gas Corporation), The Bank of New York Mellon Trust Company, N.A. (formerly known as (f/k/a) The Bank of New York Trust Co., N.A.) as Trustee and Wilmington Trust Company as Delaware Trustee [Incorporated herein by reference to Exhibit 3.1 to the Trust’s Current Report on Form 8-K filed on April 30, 2008 (File No. 001-34026)].

10.1*

  

Conveyance of Net Profits Interest, dated April 30, 2008, from Whiting Oil and Gas Corporation and Equity Oil Company (subsequently merged into Whiting Oil and Gas Corporation) to The Bank of New York Mellon Trust Company, N.A. (f/k/a The Bank of New York Trust Co., N.A.) as Trustee of Whiting USA Trust I [Incorporated herein by reference to Exhibit 10.1 to the Trust’s Current Report on Form 8-K filed on April 30, 2008 (File No. 001-34026)].

10.2*

  

Administrative Services Agreement, dated April 30, 2008, by and between Whiting Oil and Gas Corporation and The Bank of New York Mellon Trust Company, N.A. (f/k/a The Bank of New York Trust Co., N.A.) as Trustee of Whiting USA Trust I [Incorporated herein by reference to Exhibit 10.2 to the Trust’s Current Report on Form 8-K filed on April 30, 2008 (File No. 001-34026)].

10.3*

  

Registration Rights Agreement, dated April 30, 2008, by and between Whiting Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A. (f/k/a The Bank of New York Trust Co., N.A.) as Trustee of Whiting USA Trust I [Incorporated herein by reference to Exhibit 10.3 to the Trust’s Current Report on Form 8-K filed on April 30, 2008 (File No. 001-34026)].

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 11, 2013 (included as Appendix 1 of this Annual Report on Form 10-K).

 

 

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