10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

___________________________________________________________

FORM 10-K

☑	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934
	for The Fiscal Year Ended December 31, 2016

or

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934
	for the transition period from _______ to _______

Commission File Number 001-35459

___________________________________________________________

WHITINGUSATRUSTII

(Exact name of registrant as specified in its charter)

Delaware	38-7012326
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
The Bank of New York Mellon Trust Company, N.A., Trustee
Global Corporate Trust
919 Congress Avenue, Suite 500
Austin, Texas	78701
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (512) 236-6599

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

None

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☑.

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☑.

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☑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. ☑

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):

Largeacceleratedfiler☐	Acceleratedfiler☐	Non‑acceleratedfiler☑	Smallerreportingcompany☐
		(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 ☑

The aggregate market value of Units of Beneficial Interest in Whiting USA Trust II held by non-affiliates at the closing sales price on June 30, 2016 of $0.72 was $13,248,000.

As of March 10, 2017,  18,400,000 Units of Beneficial Interest in Whiting USA Trust II were outstanding.

Documents Incorporated By Reference: None

TABLE OF CONTENTS

Forward-Looking Statements	1
Glossary of Certain Definitions	2

PART I
Item 1.	Business	7
Item 1A.	Risk Factors	20
Item 1B.	Unresolved Staff Comments	31
Item 2.	Properties	32
Item 3.	Legal Proceedings	38
Item 4.	Mine Safety Disclosures	38
PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	39
Item 6.	Selected Financial Data	40
Item 7.	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	49
Item 8.	Financial Statements and Supplementary Data	50
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	63
Item 9A.	Controls and Procedures	63
Item 9B.	Other Information	64
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	64
Item 11.	Executive Compensation	64
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	64
Item 13.	Certain Relationships, Related Transactions and Director Independence	65
Item 14.	Principal Accounting Fees and Services	65
PART IV
Item 15.	Exhibits and Financial Statement Schedules	66
Item 16.	Form 10-K Summary	66

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

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). 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 Operations” are forward-looking statements. No assurance can be given that such expectations will prove to have been correct. When used in this document, the words “believes,” “expects,” “anticipates,” “intends” or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this Form 10‑K, could affect the future results of the energy industry in general, Whiting and the Trust in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:

· the effect of changes in commodity prices and conditions in the capital markets;

· uncertainty of estimates of oil and natural gas reserves and production;

· risks incident to the operation and drilling of oil and natural gas wells;

· future production and development costs;

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

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

· the effect of existing and future laws and regulatory actions;

· competition from others in the energy industry;

· inflation or deflation; and

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

This Form 10-K describes other important factors that could cause actual results to differ materially from expectations of Whiting and the Trust, including under the caption “Risk Factors.” All subsequent written and oral forward-looking statements attributable to Whiting or the Trust or persons acting on behalf of Whiting or the Trust are expressly qualified in their entirety by such factors. The Trust assumes no obligation, and disclaims any duty, to update these forward-looking statements.

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GLOSSARY OF CERTAIN DEFINITIONS

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

“ASC” Accounting Standards Codification.

“August 2014 distribution” The cash distribution to Trust unitholders of record on August 19, 2014 that was paid on August 29, 2014.

“August 2015 distribution” The cash distribution to Trust unitholders of record on August 19, 2015 that was paid on August 31, 2015.

“August 2016 distribution” The net profits generated by the NPI during the second quarterly payment period of 2016, which net profits were offset in their entirety by the Trust’s repayment of the May 2016 net loss and the current period’s provision for estimated Trust expenses, resulting in no distribution being made to Trust unitholders of record on August 19, 2016.

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

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

“BOE/d” One BOE per day.

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

“CO2”  Carbon dioxide.

“completion” The process of preparing an oil and gas wellbore for production through installation of permanent production equipment, as well as perforation and fracture stimulation to optimize production.

“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 price, and the wellhead price received.

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

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

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

“FASB”Financial Accounting Standards Board.

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

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“February 2015 distribution” The cash distribution to Trust unitholders of record on February 19, 2015 that was paid on March 2, 2015.

“February 2016 net loss”The net loss generated by the NPI during the fourth quarterly payment period of 2015, which resulted in no distribution being made to Trust unitholders of record on February 19, 2016.

“February 2017 distribution”The cash distribution to Trust unitholders of record on February 19, 2017 (which resulted in an effective record date of February 17, 2017 due to the 19th of February falling on a non-trading day) that was paid on March 1, 2017.

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

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

“gross acres” or “gross wells” The total acres or wells, as the case may be, in which a working interest is owned.

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

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

“May 2014 distribution” The cash distribution to Trust unitholders of record on May 20, 2014 that was paid on May 30, 2014.

“May 2015 distribution” The cash distribution to Trust unitholders of record on May 20, 2015 that was paid on June1, 2015.

“May 2016 net loss” The net loss generated by the NPI during the first quarterly payment period of 2016, which resulted in no distribution being made to Trust unitholders of record on May 20, 2016.

“Money market rate” The lesser of (a) the rate of interest per annum publicly announced from time to time in the Midwest edition of the Wall Street Journal as the “money market” interest rate on an annual yield basis, but if such rate is not available, then such similar rate as reported by a nationally recognized financial news source or (b) the maximum rate of interest permitted under applicable law.

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

“MBOE” One thousand BOE.

“MBOE/d” One MBOE per day.

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

“MMBOE” One million BOE.

“MMBtu” One million Btu, used in reference to natural gas.

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

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

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

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“net profits interest” or “NPI”The nonoperating interest that creates a share in gross production from an operating or working interest in the underlying properties until terminated pursuant to its terms. The share is measured by net profits from the sale of production after deducting costs associated with that production.

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

“November 2014 distribution” The cash distribution to Trust unitholders of record on November 19, 2014 that was paid on December 1, 2014.

“November 2015 distribution” The cash distribution to Trust unitholders of record on November 19, 2015 that was paid on November30, 2015.

“November 2016 distribution” The cash distribution to Trust unitholders of record on November 19, 2016 (which resulted in an effective record date of November 18, 2016 due to the 19th of November falling on a non-trading day) that was paid on November 29, 2016.

“NGL” Natural gas liquid.

“NYMEX” The New York Mercantile Exchange.

“payment period” A calendar quarter, which is the period of time over which the computation of net proceeds (or net losses) generated by the NPI is determined for the respective quarter.

“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 legally require plugging of abandoned wells.

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

“proved developed reserves” Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

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

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

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

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

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

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

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

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

“proved undeveloped reserves” Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

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

“recompletion”An operation whereby a completion in one zone is abandoned in order to attempt a completion in a different zone within the existing wellbore.

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

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

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

“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.

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

“standardized measure of discounted future net cash flows”or“standardized measure” The discounted future net cash flows relating to proved reserves based onthe 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

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are defined by contractual arrangements, excluding escalations based upon future conditions);current costs and statutory tax rates (to the extent applicable); and a 10% annual discount rate.

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

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

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PART I

Item 1. Business

General

Whiting USA Trust II (the “Trust”) is a statutory trust formed on December 5, 2011 under the Delaware Statutory Trust Act, pursuant to a trust agreement (the “Trust agreement”) among Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”) and Wilmington Trust, National Association, as Delaware Trustee (the “Delaware Trustee”). The initial capitalization of the Trust estate was funded by Whiting Petroleum Corporation (“Whiting”) on December 8, 2011. The Trust maintains its offices at the office of the Trustee, at 919 Congress Avenue, Suite 500, Austin, Texas 78701. The telephone number of the Trustee is 512-236-6599.

The Trust makes copies of its reports under the Exchange Actavailable at http://whitingwhz.investorhq.businesswire.com. The Trust’s filings under theExchange Act are also available electronically from the website maintained by the 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, 2011, the Trust had no assets other than a de minimis cash balance from its initial capitalization and had conducted no operations other than organizational activities. In  March 2012, the Trust issued 18,400,000 units of beneficial interest in the Trust (“Trust units”) to Whiting in exchange for the conveyance of the term NPI by Whiting Oil and Gas. The NPI represents the right for the Trust to receive 90% of the net proceeds from Whiting’s interests in certain existing oil, natural gas and natural gas liquid producing properties which are referred to as “the underlying properties”. The underlying properties are located in the Permian Basin,Rocky Mountains, Gulf Coast and Mid-Continent regions. The underlying properties include interests in 1,314 gross (379.4 net) producing oil and gas wells as of December 31, 2016. Whiting completed an initial public offering of Trust units selling all of its 18,400,000 units on March 28, 2012.

The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date,which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), or (b) the sale of the net profits interest. The Trust is required to sell the NPI and liquidate if cash proceeds to the Trust from the net profits interest are less than $2.0 million for each of any two consecutive years. During the year ended December 31, 2016, the Trust received cash proceeds of $1.9 million from the net profits interest. The Trust also received cash proceeds of $1.5 million from the NPI during the first calendar quarter of 2017. Therefore, if the cash proceeds to the Trust from the net profits interest are less than $0.5 million over the remaining three calendar quarters of 2017, the Trust will be required to sell the NPI and terminate. After the termination of the Trust, it will pay no further distributions.

As of December 31, 2016,  on a cumulative accrual basis6.89MMBOE (65%)  of the 10.61 MMBOE attributable to the NPI have been produced and soldor divested. Further detail on the reserves is provided herein under the section titled “Properties—Description of the Underlying Properties — Reserves”, and such reserve information is based upon a reserve report prepared by independent reserve engineers Cawley, Gillespie & Associates, Inc. for the underlying properties as ofDecember 31, 2016, which isreferred to as the “reserve report.” According to the reserve report, the portion of the 11.79 MMBOE (10.61 MMBOE at the 90% NPI) reserve quantities attributable to the NPI not yet produced and sold or divestedas ofDecember 31, 2016is projected to be produced from the underlying properties by July 31, 2023,  which reserve report is based onNYMEX oil and gas prices of $42.75 per Bbl and $2.49 per MMBtu pursuant to current SEC and FASB guidelines and the other assumptions included therein.The averageNYMEX oil and gas prices for the month of January 2017 were $52.61 per Bbl and $3.68 per MMBtu, respectively.  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, 2016 was approximately 81%oil and approximately 19% natural gas.

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, 2014 (which hedging effects extended through the quarterly payment period covered by the February 2015 distribution to unitholders), and no additional hedges are allowed to be placed on the Trust assets. Thus, there are no further cash settlements on commodity hedges, and the Trust therefore has increased exposure to oil and natural gas price volatility.

Net proceeds payable to the Trust depend upon production quantities; sales prices of oil, natural gas and natural gas liquids; costs to develop and produce the oil and gas; and realized cash settlements from commodity derivative contracts. In calculating net proceeds, Whiting deducts from gross oil and natural gas sales proceeds, lease operating expenses (including costs of workovers), production

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

On January 4, 2016,the New York Stock Exchange (the “NYSE”) informed the Trust that the Trust was not in compliance with the NYSE’s continued listing standards, which require that the average closing price of the Trust units cannot be less than $1.00 per share over a period of 30 consecutive trading days. Under the NYSE delisting procedures, the Trust had the right to certain cure periods if it could demonstrate its intent to cure the deficiency. However, in order to save the Trust administrative costs, including potential significant expenses associated with reverse split votes or other actions intended to remedy the deficiency and ongoing NYSE listing fees, the Trust determined that it would not cure the deficiency. As a result, the Trust units ceased trading on the NYSE on January 6, 2016. The Trust units transitioned to OTC, operated by OTC Markets Group, effective with the opening of trading on January 7, 2016 under the trading symbol “WHZT.” The Trust can provide no assurance that any trading market for the Trust units will exist on OTC or that current trading levels will be sustained or not diminish.

The Trust makes quarterly cash distributions of substantially all of its quarterly cash receipts, if any, after the deduction of fees and expenses for the administration of the Trust, to holders of its Trust units. Because payments to the Trust are generated by depleting assets and the Trust has a finite life due to the production from the underlying properties diminishing over time, a portion of each distribution represents a return of the original investment in the Trust units, with the remainder being considered as a return on investment. As a result, the market price of the Trust units will decline to zero at termination of the Trust.

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

The Trust was created to acquire and hold the term NPI for the benefit of the Trust unitholders pursuant to the conveyance to the Trust from Whiting Oil and Gas.The NPI is the only asset of the Trust, other than cash reserves held for future Trust expenses.The NPI is passive in nature, and the Trustee has no management control over and no responsibility relating to the operation of the underlying properties. The business and affairs of the Trust are administered by the Trustee. 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. The table below presents percentages by purchaser that accounted for 10% or more of the oil, NGL and natural gas sales attributable to the NPI for the years ended December 31, 2016, 2015 and 2014.

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	2016	2015	2014
Plains Marketing, LP	16%	15%	15%
Chevron USA	15%	15%	15%
Phillips 66 Company	11%	11%	11%
Marathon Oil Corporation	9%	14%	11%

Whiting does not believe that the potential loss of any of these purchasers presents a material risk because there is significant competition among purchasers of crude oil and natural gas in the areas of the underlying properties, and if the underlying properties were to lose any of their largest purchasers, several entities could reasonably be expected to purchase crude oil and natural gas produced from the underlying properties with little or no interruption to their sales.

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 cashflow. The Trust is subject to the same competitive conditions as Whiting and other companies in the oil and natural gas industry.

Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas. Future price fluctuations for oil, natural gas and natural gas liquids will directly impact Trust distributions, estimates of reserves attributable to the NPI and estimated and actual future net revenues to the Trust. In light of the many uncertainties that affect the supply and demand for oil and natural gas, neither the Trust nor Whiting can make reliable predictions of future oil and natural gas supply and demand, future product prices or the effect of future product prices on the Trust.

Description of Trust Units

Each Trust unit is a unit of beneficial interest in the Trust and is entitled to receive cash distributions from the Trust on a pro rata basis.Each Trust unitholder has the same rights regarding each of his or her Trust units as every other Trust unitholder has regarding his or her units. The Trust units are in book-entry form only and are not represented by certificates.

Periodic Reports

The Trustee files all required Trust federal and state income tax and information returns. The Trustee prepares and mails to Trust unitholders annual reports that Trust unitholders need to correctly report their share of the Trust’s income and deductions. The Trustee also causes to be prepared and filed reports required under the Exchange Act 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 of 2002, 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 GeneralCorporation 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

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before the meeting. Trust unitholders representing a majority of Trust units outstanding must be present or represented to have a quorum. Each Trust unitholder is entitled to one vote for each Trust unit owned.

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

· dissolve the Trust;

· remove the Trustee or the Delaware Trustee;

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

· merge or consolidate the Trust with or into another entity;

· approve the sale of assets of the Trust unless the sale involves the release of less than or equal to 0.25% of the total production from the underlying properties for the last twelve months and the aggregate asset sales do not have a fair market value in excess of $1.0 million for the last twelve months; or

· agree to amend or terminate the conveyance.

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

Termination of the Trust; Sale of the Net Profits Interest

The NPI will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), and the Trust will soon thereafter wind up its affairs and terminate, after which it will pay no further distributions and the market price of Trust units will have declined to zero.  The remaining reserve quantities are projected to be produced by July 31, 2023, based on the Trust’s reserve report as of December 31, 2016.

The Trust will dissolve prior to the termination of the NPI if:

· the Trust sells the NPI;

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

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

· the Trust is judicially dissolved.

The Trustee would then sell all of the Trust’s assets, either by private sale or public auction, and distribute the net proceeds of the sale to the Trust unitholders.

During the year ended December 31, 2016, the Trust received cash proceeds of $1.9 million from the net profits interest. The Trust also received cash proceeds of $1.5 million from the NPI during the first calendar quarter of 2017. Therefore, if the cash proceeds to the Trust from the net profits interest are less than $0.5 million over the remaining three calendar quarters of 2017, the Trust will be required to sell the NPI and terminate. After the termination of the Trust, it will pay no further distributions.

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 filed as an exhibit to this Annual Report on Form 10-K.

Net Profits Interest

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

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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, if any, 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 when the NPI generates distributable income.

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

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

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

· the aggregate amounts paid by Whiting upon settlement of the hedge contracts on a quarterly basis, as specified in the hedge contracts, which all terminated as of December 31, 2014;

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

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

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

· costs paid pursuant toexisting operating agreements, including producing overhead charges;

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

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

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

All of the hedge payments received by Whiting from the counterparty upon settlements of hedge contracts and certain other non-production revenues, as detailed in the conveyance,offset the production and development costs outlined above (such production and development costs excluding the last bullet point above) in calculating the net proceeds. Plugging and abandonment liabilities relating to the underlying properties will not be deducted from the gross proceeds in determining net proceeds. If certain other non-production revenues exceed the operating expenses during a quarterly period, the use of such excess amounts to offset operating expenses may be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period when such amounts, together with other offsets to costs for the applicable quarter, are less than such expenses. If any excess amounts have not been used to offset costs at the time when the NPI terminates or is sold, then unitholders will not be entitled to receive the benefit of such excess amounts.

During each twelve-month period beginning on the later to occur of (1) December 31, 2017 and (2) the last day of the payment period during which 8.24 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 7.41 MMBOE in respect of the NPI) (in either case, the “capital expenditure limitation date”), the sum of the capital expenditures and amounts reserved for approved capital expenditure projects for such twelve-month period may not exceed the average annual capital expenditure amount. The “average annual capital expenditure amount” means the quotient of (x) the sum of the capital expenditures and amounts reserved for approved capital expenditure projects with respect to the three twelve-month periods ending on the capital expenditure limitation date, divided by (y) three. Commencing on the capital expenditure limitation date, and each anniversary of the

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capital expenditure limitation date thereafter, the average annual capital expenditure amount will be increased by 2.5% to account for expected increased costs due to inflation.

Pursuant to the terms of its applicable joint operating agreements, Whiting deducts from gross proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally, with respect to those underlying properties for which Whiting is the operator but where there is no operating agreement in place, Whiting deducts from the gross proceeds an overhead fee calculated in the same manner that Whiting allocates overhead to other similarly owned properties,  as is customary in the oil and gas industry.Operating overhead activities include various engineering, legal and administrative functions. The Trust’s portion of the monthly charge averaged $409per month per active operated well, which totaled $1.6 millionfor the fourdistributions made during the year ended December 31, 2016. 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 marketrate 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, which all terminated as of December 31, 2014, and Whiting in turn conveyed to the Trust the rights and obligations to future hedge payments Whiting makes or receives under such costless collar hedge contracts. These contracts were entered into to reduce the exposure to volatility in the underlying properties’ oil revenues due to fluctuations in crude oil prices, and to achieve more predictable cash flows. Historically, prices received for oil production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general economic conditions. Costless collars are designed to establish floor and ceiling prices on anticipated future production. The hedge contracts were in place during the 2014 period presented in this Annual Report on Form 10-K. However, all hedging contracts terminated as of December 31, 2014 (which hedging effects extended through the February 2015 distribution to unitholders and ceased thereafter). No additional hedges are allowed to be placed on Trust assets,  and the Trust cannot therefore enter into derivative contracts for speculative or trading purposes. Consequently, there are no future cash settlement gains or losses on commodity derivatives, and the Trust therefore has increased exposure to oil and natural gas price volatility.

Crude oil costless collar arrangements settle based on the average of the closing settlement price for each commodity business day in the contract period. In a collar arrangement, the counterparty is required to make a payment to Whiting for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. Whiting is required to make a payment to the hedge counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price.

Any amounts received by Whiting from the hedge contract counterparty upon settlements of the hedge contracts reducedproduction and development costs attributable to the underlying properties in calculating the net proceeds. The hedge contracts covered only a portion of production and applied only to production through December 31, 2014.

Additional Provisions

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

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

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

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

The Trustee is not obligated to return any cash received from the NPI. Any overpayments made to the Trust by Whiting due to adjustments to prior calculations of net proceeds or otherwise will reduce future amounts payable to the Trust until Whiting recovers the overpayments plus interest at the prevailing money marketrate. Whiting may make such adjustments to prior calculations of net

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proceeds without the consent of the Trust unitholders or the Trustee, but is required to provide the Trustee with notice of such adjustments and supporting data.

In addition, Whiting may, without the consent of the Trust unitholders, require the Trust to sell the net profits interest associated with any well or lease that accounts for less than or equal to 0.25% of the total production from the underlying properties in the prior 12 months, provided that the net profits interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the Trust of $1.0 million. These releases will be made only in connection with a sale by Whiting of the relevant underlying properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such portion of theNPI. Any net sales proceeds paid to the Trust are distributable to Trust unitholders in the quarter in which they are received. In 2016 and 2015, Whiting completed divestitures of certain producing and shut-in wells for sales proceeds attributable to the Trust’s interest of $58,500 and $0.3 million, respectively, which properties had proved reserves of 16.32 MBOE with respect to the Trust’s 90% net profits interest. For further information on these divestitures refer to “Abandonment, Sale and Farm-out of Underlying Properties” in Item 2 of this Annual Report on Form 10-K.

For the underlying properties for which Whiting is the designated operator,  it may enter into farm-out, operating, participation and other similar agreements with respect to the property. Whiting may enter into any of these agreements without the consent or approval of the Trustee or any Trust unitholder. During April 2016, Whiting entered into a farm-out agreement for certain underlying properties in the Keystone South Field located in Winkler County, Texas. Additionally, in February 2017, Whiting entered into a farm-out agreement for certain underlying properties in the Signal Peak field located in Howard County, Texas. Refer to “Abandonment, Sale and Farm-out of Underlying Properties” in Item 2 of this Annual Report on Form 10-K for additional information related to these farm-out agreements.

Whiting or any other operator has the right to abandon any well or property if it reasonably believes the well or property ceases to produce or is not capable of producing in commercially paying quantities. In making such decisions, Whiting is required under the applicable conveyance to operate, or to use commercially reasonable efforts to cause the operators of the underlying properties to operate, the underlying properties as a reasonably prudent operator in the same manner it would if these properties were not burdened by the NPI. Upon termination of the lease, the portion of the NPI relating to the abandoned property will be extinguished.

Whiting must maintain books and records sufficient to determine the amounts payable under the NPI to the Trust. Quarterly and annually, Whiting must deliver to the Trustee a statement of the computation of net proceeds for each computation period. The Trustee has the right to inspect and copy the books and records maintained by Whiting during normal business hours and upon reasonable notice.

Federal Income Tax Matters

The following is a summary of certain U.S. federal income tax matters that may be relevant to the Trust unitholders. This summary is based upon current provisions of the Internal Revenue Code of 1986, as amended, which is referred to as the “Code,” existing (and to the extent proposed) Treasury regulations thereunder, and current administrative rulings and court decisions, all of which are subject to change or different interpretation at any time, possibly with retroactive effect. No attempt has been made in the following summary to comment on all U.S. federal income tax matters affecting the Trust or the Trust unitholders.

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

Classification and Taxation of the Trust

Tax counsel to the Trust advised the Trust at the time of formation that, for U.S. federal income tax purposes, in its opinion, the Trust would be treated as a grantor trust and not as an unincorporated business entity. No ruling has been or will be requested from the IRS or another taxing authority. The remainder of the discussion below is based on tax counsel’s opinion, at the time of formation, that the Trust will be classified as a grantor trust for U.S. federal income tax purposes. As a grantor trust, the Trust is not subject to U.S. federal income tax at the Trust level. Rather, each Trust unitholder is considered for federal income tax purposes to own and receive its proportionate share of the Trust’s assets directly as though no Trust were in existence. The income of the Trust is deemed to be received or accrued by the Trust unitholder at the time such income is received or accrued by the Trust, rather than when distributed by the Trust. Each Trust unitholder is subject to tax on its proportionate share of the income and gain attributable to the assets of the Trust and is entitled toclaim its proportionate share of the deductions and expenses attributable to the assets of the Trust, subject to

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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 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, Suite 500, Austin, Texas 78701, telephone number 512-236-6599, 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 2016federal 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 athttp://whitingwhz.investorhq.businesswire.com.

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

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

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the case of an estate or trust, the tax is imposed on the lesser of (x) undistributed net investment income, or (y) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Environmental Matters and Regulation

The operations of the underlying properties are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the release, discharge or emission of materials into the environment; the handling of hazardous materials; or otherwise relating to environmental protection. These laws and regulations may, among other things:

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

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

· limit or prohibit drilling activities in sensitive areas, such as wilderness areas, wetlands, streams or areas that may contain endangered or threatened species and their habitats;

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

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

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

Failure to comply with these laws and regulations may result in the assessment of significant administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, these laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly well construction, drilling, water management or completion activities or waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on the operating costs of the properties comprising the underlying properties.

President Trump has indicated that he would work to ease regulatory burdens on industry and on the oil and gas sector, including environmental regulations. However, any executive orders the President may issue or any new legislation Congress may pass with the goal of reducing environmental statutory or regulatory requirements may be challenged in court. In addition, various state laws and regulations (and permits issued thereunder) will be unaffected by federal changes unless and until the state laws and corresponding permits are similarly changed, and any judicial review is completed.

The following is a summary of the more significant existing laws, rules and regulations to which the operations of the underlying properties are subject that are material to the operation of the underlying properties.

Waste Handling.The Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage and disposal of hazardous and non-hazardous wastes. Under delegations of authority from the U.S. Environmental Protection Agency (“EPA”) the 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 water 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. In May 2016, several environmental groups sued the EPA for failing to update its rules for management of oil and gas drilling waste under RCRA. The petitioners requested that the EPA revise its regulations for waste materials generated as a result of oil and gas exploration and production activities. The petitioners claimed that the EPA has not reviewed or revised its regulations for management of wastes from oil and gas exploration and production operations since 1988, even though the statute requires the EPA to review and, if necessary, revise the regulations every three years. In December 2016, the court entered a Consent Decree resolving the litigation. Under the Consent Decree, the EPA has agreed to propose no later than March 15, 2019 a rulemaking for revision of the regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. In the event that the EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA

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take final action following notice and comment rulemaking no later than July 15, 2021. Any such change in the current RCRA exemption and comparable state laws, could result in an increase in the costs to manage and dispose of wastes, which could have a material adverse effect on the cash distributions to the Trust unitholders.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”), also known as the Superfund law and comparable state laws impose strict joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be  responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed of or arranged for the disposal of the hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. While Whiting generates materials in the course of its operations of the underlying properties that may be regulated as hazardous substances, Whiting has not been notified that it has been named as a potentially responsible party at or with respect to any Superfund sites. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, waste products or other chemicals into the environment.

The underlying properties of the Trust may have been used for oil and natural gas exploration and production for many years. Although Whiting believes that it hasutilized 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 underother locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, the underlying properties of the Trust may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons and materials was not under Whiting’s control. These properties and the substances disposed or released on them may give rise to potential liabilities for Whiting pursuant to CERCLA, RCRA and analogous state laws. Under such laws, Whiting could be required to remove previously disposed substances and wastes, remediate contaminated property, perform remedial plugging or pit closure operations to prevent future contamination or to pay some or all of the costs of any such action.

Water Discharges. The Federal Water Pollution Control Act, or the Clean Water Act, as amended (the “CWA”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into state waters or other 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 watersin 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 from tight rock formations. The process involves the injection of mainly water and sand plus a de minimis amount of chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing has been utilized to complete wells drilledon the underlying properties, and Whitingexpects it will also be used in the future. The process is typically regulated by state oil and gas commissions. However, the EPA also issued guidance in 2014 for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel.

In December 2016, the EPA released a final report on the potential impacts of oil and gas fracturing activities on the quality and quantity of drinking water resources in the United States. In addition, inJune 2016, the EPA issued a final rule promulgating pretreatment standards for the oil and gas extraction category which would address discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. The EPA is also conducting a study of private wastewater treatment facilities accepting oil and gas extraction wastewater. The EPA is collecting data and information regarding the extent to which these facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of the facilities, the environmental impacts of discharges and other information.

Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy, the U.S. Government Accountability Office and the White House Council for Environmental Quality. In March 2015, the U.S. Department of the Interior released a final rule addressing (i) hydraulic fracturing on federal and Indian oil and natural gas leases to require validation of well integrity and strong cement barriers between the wellbore and water zones through which the wellbore passes, (ii) disclosure of chemicals used in hydraulic fracturing to the Bureau of Land Management, (iii) higher standards for interim storage of recovered waste fluids from hydraulic fracturing and (iv) measures to lower the risk of cross-well contamination with chemicals and fluids used

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in fracturing operations. In addition, legislation has been introduced in Congress from time to time to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that could ban, restrict or impose additional requirements on activities relating to hydraulic fracturing in certain circumstances.For example, in June 2011, Texas enacted a law that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production in Texas) and the public. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting requirements or operational restrictions and also to associated permitting delays, litigation risk and potential increases in costs. Further, local governments may seek to adopt, and some have adopted, ordinances within their jurisdictions restricting the use of or regulating the time, place and manner of drilling or hydraulic fracturing.No assurance can be given as to whether or not similar measures might be considered or implemented in the jurisdictions in which the underlying properties are located. If new laws, regulations or ordinances that significantly restrict or otherwise impacthydraulic fracturing are passed by Congress or adopted in the states or local municipalities where the underlying properties are located, such legal requirements could prohibit or 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.

In addition, in July 2014, a major university and U.S. Geological Survey researchers published a study purporting to find a causal connection between the deep well injection of hydraulic fracturing wastewater and a sharp increase in seismic activity in Oklahoma since 2008. This study, as well as subsequent studies and reports, may trigger new legislation or regulations that would limit or ban the disposal of hydraulic fracturing wastewater in deep injection wells. If such new laws or rules are adopted, operations on the underlying properties may be curtailed while alternative treatment and disposal methods are developed and approved, or the costs of operations on the underlying properties may increase, which could reduce cash distributions by the Trust and the value of Trust units.

Global Warming and Climate Change.  In December 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 adopted and implemented regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, as amended (the “CAA”), including rules that limit emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHGs emission standards trigger the CAA construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards took effect in January 2011. In June 2010, the EPA also publishedits final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (the “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 becoming 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. Whiting believes that it is in compliance with all substantial applicable emissions requirements.

In June 2014, the Supreme Court upheld most of the EPA’s GHGs permitting requirements, allowing the agency to regulate the emission of GHGs from stationary sources already subject to the PSD and Title V requirements. Certain of Whiting’s equipment and installations may currently be subject to PSD and Title V requirements and hence, under the Supreme Court’s ruling, may also be subject to the installation of controls to capture GHGs. For any equipment or installation so subject, Whiting may have to incur increased compliance costs to capture related GHGs emissions, which could reduce cash distributions by the Trust and the value of Trust units.

In October 2016, the EPA proposed revisions to the rule applicable to GHGs for PSD and Title V permitting requirements. The proposed rule, which would not expand federal GHG air permitting requirements, has not been finalized.

In accordance with President Obama’s Climate Action Plan, inAugust 2015, the EPA issued a rule to reduce carbon emissions from electric generating units. The rule, commonly called the “Clean Power Plan,” requires states to develop plans to reduce carbon

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emissions from fossil fuel-fired generating units commencing in 2022, with the reductions to be fully phased in by 2030. Each state is given a different carbon reduction target, but the EPA expects that, in the aggregate, the overall proposal will reduce carbon emissions from electric generating units by 32% from 2005 levels. States are given substantial flexibility in meeting their emission reduction targets and can generally choose to lower carbon emissions by replacing higher carbon generation, such as coal or natural gas, with lower carbon generation, such as efficient natural gas units or renewable energy alternatives.Several industry groups and states have challenged the Clean Power Plan in the Court of Appeals for the D.C. Circuit, and in February 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan while it is being challenged in court. The Court of Appeals for the D.C. Circuit heard oral arguments on the Clean Power Plan in September 2016, but has not yet issued a decision. President Trump has indicated that he is opposed to the Clean Power Plan, and the new administration could withdraw the rule and potentially repropose it, or seek to invalidate the EPA’s prior determination that GHGs present an endangerment to public health and the environment. Either action is likely to be challenged in court, which could delay implementation of any new rules.

In addition, both houses of Congress have actively 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, GHG 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 that could adversely affect demand for the oil, natural gas liquids and natural gas produced. Finally, it should be noted that many scientists have concluded that increasing concentrations of GHGs in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events.

Air Emissions. The CAA and comparable state laws regulate emissions of various air pollutants from various industrial sources through air emissions permitting programs and also impose other monitoring and reporting requirements. Operators of the underlying properties, including Whiting, may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining pre-construction and operating permits and approvals for air emissions. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. For example, in 2012, the EPA finalized rules establishing new air emission controls for oil and natural gas production operations. Specifically, the EPA’s rule includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. Among other things, these standards require the application of reduced emission completion techniques associated with the completion of newly drilled and fractured wells in addition to existing wells that are refractured. The rules also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. These rules could require a number of modifications to operations at the underlying properties including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact cash distributions to unitholders.  Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

The EPA announced in 2015 that it would directly regulate methane emissions from oil and natural gas wells for the first time as part of President Obama’s Climate Action Plan. As part of this strategy, in May 2016, the EPA issued three final rules. The EPA issued a final rule that updated the New Source Performance Standards to add requirements that the oil and gas industry reduce emissions of greenhouse gases and to cover additional equipment and activities in the oil and gas production chain. The final rule sets emissions limits for methane, which is the principal greenhouse gas emitted by equipment and processes in the oil and gas sector. This rule applies to new, reconstructed and modified processes and equipment. This rule also expands the volatile organic compound emissions limits to hydraulically fractured oil wells and equipment used across the industry that was not regulated in the 2012 rules. The rule also requires owners and operators to find and repair leaks, also known as “fugitive emissions.” The EPA also issued a final rule known as the Source Determination Rule, which is intended to clarify when multiple pieces of equipment and activities in the oil and gas industry must be deemed a single source when determining whether major source permitting programs apply under the prevention of significant deterioration, nonattainment new source review preconstruction and operation permit programs under Title V of the CAA (“Title V”). The final rule defines the term “adjacent” to clarify that equipment and activities in the oil and gas sector that are under common control will be considered part of the same source if they are located near each other – specifically, if they are located on the same site, or on sites that share equipment and are within one quarter of a mile of each other. This rule applies to equipment and activities used for onshore oil and natural gas production, and for natural gas processing.

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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 in September 2011, the U.S. Fish and Wildlife Serviceis required to make a determination on listing more than 250 species as endangered or threatened under the ESA over the next several years. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause operators of those underlying properties, including Whiting, to incur increased costs arising from species protection measures or could result in limitations on their exploration and production activities that could have an adverse impact on their ability to develop and produce reserves.

Consideration of Environmental Issues in Connection with GovernmentalApprovals. Whiting’s operations frequently require licenses, permits and/or other governmental approvals. Several federal statutes, including the Outer Continental Shelf Lands Act (“OCSLA”) and the National Environmental Policy Act (“NEPA”) require federal agencies to evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions. OCSLA, for instance, requires the U.S. Department of Interior to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or human environment. Similarly, NEPA requires the Department of Interior and other federal agencies to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency would have to prepare an environmental assessment and, potentially, an environmental impact statement. This process has the potential to delay the development of oil and natural gas projects.

Whiting believes that it is in compliance in all material respects with all existing environmental laws and regulations applicable to the current operations of the underlying properties and that its continued compliance with existing requirements will not have a material adverse effect on the cash distributions to the Trust unitholders. For instance, Whiting did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2016 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 2017 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 amounts of cash distributions by the Trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquids prices.

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, including, but not limited to, the following:

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

· the level of global oil and natural gas inventories;

· 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;

· developments of United States energy infrastructure, such as the recent delays in constructing the Dakota Access Pipeline;

· weather conditions;

· technological advances affecting energy consumption;

· current and anticipated changes to domestic and foreign governmental regulations, including those that may arise in response to the policies of the Trump Administration;

· 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.

These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements. Also, prices for crude oil and prices for natural gas do not necessarily move in tandem. Declines in oil or natural gas prices would not only reduce revenue, but could also reduce the amount of oil and natural gas that can be economically produced from the underlying properties.

Oil prices have fallen significantly since reaching highs of over $105.00 per Bbl in June 2014, dropping below $27.00 per Bbl in February 2016. Natural gas prices have also declined from over $4.80 per MMBtu in April 2014 to below $1.70 per MMBtu in March 2016. Although oil prices have recently begun to recover from the lows experienced during the first quarter 2016, forecasted prices for oil and natural gas remain low.

Whiting entered into hedge contracts, which were structured as costless collar arrangements and 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, 2014 (which hedging effects extended through the February 2015 distribution to unitholders), and no additional hedges are allowed to be placed on the Trust assets. As a result, the amounts of the cash distributions may fluctuate significantly as a result of changes in commodity prices because there are no hedge contracts in place to reduce the Trust’s exposure to oil and natural gas price volatility.

Substantial and extended declines in oil, natural gas and natural gas liquids prices have resulted and may continue to result in reduced 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,

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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, or sustained periods of low prices, of oil, natural gas or natural gas liquids, that have continued through 2016, will likely materially reduce, or completely eliminate, the amount of cash available for distribution to Trust unitholders.

There will be no distribution to unitholders when the amount of any costs, expenses and reserves related to the underlying properties, other costs and expenses incurred by the Trust and prior period net losses and applicable accrued interest, exceeds or equals the gross proceeds generated by the NPI, as occurred for the February 2016 net loss,May 2016 net loss and August 2016 distribution.

The NPI bears its share of all production and development costs and expenses related to the underlying properties, such as lease operating expenses, production and property taxes and development costs, which reduces or potentially eliminates the amount of cash received by the Trust and thereafter distributable to Trust unitholders. Additionally, if production and development costs on the underlying properties exceed the proceeds from production, as occurred for the February 2016  and May 2016 net losses when the NPI generated an aggregate $1.3 million net loss attributable to the Trust’s interest, 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. Also, amounts may be reserved by Whiting for future development, maintenance or operating expenses (which reserve amounts may not exceed $2.0 million), which also reduces the amount of cash received by the Trust and thereafter be distributable to Trust unitholders.

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

If the NPI does not generate $2.0 million of annual cash proceeds during the year ending December 31, 2017, the Trustee will 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 Trust is required to sell the NPI and liquidate if cash proceeds to the Trust from the net profits interest are less than $2.0 million for each of any two consecutive years. During the year ended December 31, 2016, the Trust received cash proceeds of $1.9 million from the net profits interest. The Trust also received cash proceeds of $1.5 million from the NPI during the first calendar quarter of 2017. Therefore, if the cash proceeds to the Trust from the net profits interest are less than $0.5 million over the remaining three calendar quarters of 2017, the Trust will be required to sell the NPI and terminate. Additionally, 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 sale of the NPI will result in the dissolution of the Trust and the net proceeds of any such sale will be distributed to the Trust unitholders.

The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), or (b) the sale of the net profits interest. The Trust unitholders will not be entitled to receive any net proceeds from the sale of production from the underlying properties following the termination of the NPI. Therefore, the market price of the Trust units will approach and eventually reach zero shortly after the end of the NPI term because cash distributions from the Trust will cease following the termination of the NPI, and the Trust will have no right to any additional production from the underlying properties after the term of the NPI.

The Trust units have been delisted from the New York Stock Exchange. It will likely be more difficult for unit holders to sell the Trust units or to obtain accurate quotations of the Trust units.

The Trust units ceased trading on the NYSE on January 6, 2016. The Trust units transitioned to OTC, operated by OTC Markets Group, effective with the opening of trading on January 7, 2016 under the trading symbol “WHZT.” The Trust can provide no assurance that any trading market for the Trust units will exist on OTC or that current trading levels will be sustained or not diminish. Securities traded on the over-the-counter markets are typically less liquid than stocks that trade on the NYSE. Trading on the over-the-counter market may negatively affect the trading price and liquidity of the Trust units and could result in larger spreads in the bid and ask prices for Trust units. Unit holders may find it difficult to resell their Trust units due to the delisting.

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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 such reserves will decline over time. The reserves attributable to the underlying properties declined 17.0% from December 31, 2015 to December 31, 2016. Based on the reserve report, overall production for both oil and gas attributable to the underlying properties is expected to decline at an average year-over-year rate of approximately 12.1% for oil and 15.4% for gas between 2017 and 2023, assuming the level of developmental drilling and investments on the underlying properties as assumed in the year-end reserve report. However, cash distributions to unitholders may decline at a faster rate than the rate of production due to fixed and semi-variable costs attributable to the underlying properties or if expected future development is delayed, reduced or cancelled. Also, the anticipated rate of decline is an estimate and actual decline rates will likely vary from those estimated. As of December 31, 2016, the percentage of remaining reserves expected to be produced during the term of the NPI was 56.1%.  The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), or (b) the sale of the net profits interest.

Future maintenance projects on the underlying properties beyond those which are currently estimated may affect the quantity of proved reserves that can be economically produced from the underlying properties. The timing and size of these projects will depend on, among other factors, the market prices of oil, natural gas and natural gas liquids. If operators of the underlying properties do not implement required maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by Whiting or estimated in the reserve report. Additionally, although Whiting retained a 10% interest in the net proceeds from the sale of oil, natural gas and natural gas liquids from the underlying properties, Whiting does not own any Trust units, which could reduce its economic incentive to operate the underlying properties in an efficient and cost-effective manner.

The Trust agreement provides that the Trust’s business activities are limited to owning the NPI and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyance related to the NPI. As a result, the Trust is not permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets or production attributable to the NPI, nor is the Trust permitted to enter into any new hedging arrangements.

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

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

The value of the Trust units and the amount of future cash distributions, if any, to the Trust unitholders depends upon, among other things, the accuracy of the production and reserves estimated to be attributable to the underlying properties and the NPI. Estimating production and reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates, and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating production and reserves. Those factors and assumptions include:

· historical production from the area compared with production rates from other producing areas;

· the assumed effect of governmental regulation; and

· assumptions about future prices of oil, natural gas and natural gas liquids, including differentials, production and development costs, gathering and transportation costs, severance and excise taxes and capital expenditures.

Changes in these assumptions may materially alter production and reserve estimates. The estimated proved reserves attributable to the NPI and the “standardized measure” value attributable to the NPI are based on estimates of reserve quantities and revenues for the underlying properties. The quantities of reserves attributable to the underlying properties and the NPI may decrease in the future as a result of future decreases in the price of oil, natural gas or natural gas liquids. For example, the reserve estimates in the reserve report have been derived from NYMEX oil and gas prices of $42.75 per Bbl and $2.49 per MMBtu, respectively, which are calculated using

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an average of the first-day-of-the month price for each month within the 12 months ended December 31, 2016, pursuant to current SEC and FASB guidelines.

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

The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold, or (b) the sale of the net profits interest. The reserve report currently projects that 11.79 MMBOE will have been produced from the underlying properties by July 31, 2023.As basis for comparison, the estimated date when such amount would have been produced according to  the 2015 year-end reserve report was June 30, 2022. However, the exact rate of production cannot be predicted with certainty and such amount may be produced before or after that date. If production attributable to the underlying properties is slower than estimated, then financial returns to purchasers of Trust units will be lower (assuming constant prices) because cash distributions attributable to such production will occur at a later date.

Risks associated with the production, gathering, transportation and sale of oil, natural gas and natural gas liquids could adversely affect cash distributions by the Trust and the value of the Trust units.

The revenues of the Trust, the value of the Trust units and the amount of cash distributions to the Trust unitholders depends upon, among other things, oil, natural gas and natural gas liquids production and the prices received and the costs incurred to exploit oil and natural gas reserves attributable to the underlying properties. Drilling, production or transportation accidents that temporarily or permanently halt the production and sale of oil, natural gas and natural gas liquids at any of the underlying properties reduces Trust distributions by reducing the amount of net proceeds available for distribution. For example, accidents may occur that result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any costs incurred in connection with any such accidents that are not insured against will have the effect of reducing the net proceeds available for distribution to the Trust. Also, Whiting does not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. Please read “— Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affecting Whiting’s and other operators’ services.” below in these Risk Factors for a discussion of the uncertainty involved in the regulation of hydraulic fracturing. Also, Whiting’s oil, natural gas liquids and natural gas production depends in large part on the proximity and capacity of pipeline systems and transportation facilities which are mostly owned by third parties. The lack of availability or the lack of capacity on these systems and facilities could result in the curtailment of production or the delay or discontinuance of drilling plans. Similarly, curtailments or damage to pipelines and other transportation facilities 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, in response to recent accidents involving rail cars carrying Bakken crude oil, the U.S. Department of Transportation (the “DOT”) issued an emergency order on February 25, 2014 that requires rail shippers to test the makeup of such crude oil before transporting it. This move follows the safety alert the DOT issued in January 2014 that Bakken formation crude oil is more flammable than other types of crude oil and has been followed by additional emergency orders and safety advisories and alerts. An accident involving rail cars could result in significant personal injuries and property and environmental damage. In May 2015, the Pipeline and Hazardous Material Safety Administration issued new rules applicable to “high-hazard flammable trains”, which could increase transportation expenses. Similarly, regulatory responses to the October 2015 failure at a Southern California underground natural gas storage facility could also lead to increased expenses for underground storage.

In addition, drilling, production and transportation of hydrocarbons bear the 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 air, soil, ground water, and surface water, as well as potential fines, penalties or damages associated with any of the foregoing consequences.

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 around or shortly after the NPI termination date, which is currently estimated to be July 31, 2023.

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

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Trust, including prevailing sales prices of oil, natural gas and natural gas liquids production attributable to the underlying properties. Further, the market price of Trust units may be affected by factors other than the anticipated future Trust distributions. Consequently, the market price for the Trust units may not necessarily be indicative of the value that the Trust would realize if it sold the NPI to a third-party buyer. In addition, such market price may not necessarily reflect the fact that since the assets of the Trust are depleting assets, a portion of each cash distribution paid, if any, 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 shortly after the NPI termination date, which is currently estimated to be July 31, 2023 based on the reserve report as of December 31, 2016.

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

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

· substantial or extended declines in oil, NGL and natural gas prices;

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

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

· pressure or irregularities in geological formations;

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

· equipment failures or accidents;

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

· pipeline takeaway and refining and processing capacity; and

· title problems.

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

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

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. Hydraulic fracturing has been utilized during the completion of wells drilled on the underlying properties, and Whiting expects it will also be used in the future. The process involves the injection of mainly water and sand plus a de minimis amount of chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA has also issued guidance in 2014 for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel.

In December 2016, the EPA released a final report on the potential impacts of oil and gas fracturing activities on the quality and quantity of drinking water resources in the United States.

In addition, in June 2016 the EPA issued a final rule promulgating pretreatment standards for the oil and gas extraction category which addresses discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. The EPA is also conducting a study of private wastewater treatment facilities accepting oil and gas extraction wastewater. The EPA is collecting data and information regarding the extent to which these facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of the facilities, the environmental impacts of discharges and other information.

Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy, the U.S. Government Accountability Office and the White House Council for Environmental Quality. In March 2015, the U.S. Department of the Interior released a final rule addressing (i) hydraulic fracturing on federal and Indian oil and natural gas leases to require validation of well integrity and strong cement barriers between the wellbore and water zones through which the wellbore passes, (ii) disclosure of chemicals used in hydraulic fracturing to the Bureau of Land Management, (iii) higher standards for interim storage of recovered

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waste fluids from hydraulic fracturing and (iv) measures to lower the risk of cross-well contamination with chemicals and fluids used in fracturing operations. In addition, legislation has been introduced in Congress from time to time to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that could ban, restrict or impose additional requirements on activities relating to hydraulic fracturing in certain circumstances. For example, in June 2011, Texas enacted a law that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production in Texas) and the public. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting requirements or operational restrictions and also to associated permitting delays, litigation risk and potential increases in costs. Further, local governments may seek to adopt, and some have adopted, ordinances within their jurisdictions restricting the use of or regulating the time, place and manner of drilling or hydraulic fracturing. No assurance can be given as to whether or not similar measures might be considered or implemented in the jurisdictions in which the underlying properties are located. If new laws, regulations or ordinances that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in the states or local municipalities where the underlying properties are located, such legal requirements could prohibit or 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.

In addition, in July 2014, a major university and U.S. Geological Survey researchers published a study purporting to find a causal connection between the deep well injection of hydraulic fracturing wastewater and a sharp increase in seismic activity in Oklahoma since 2008. This study, as well as subsequent studies and reports may trigger new legislation or regulations that would limit or ban the disposal of hydraulic fracturing wastewater in deep injection wells. If such new laws or rules are adopted, operations on the underlying properties may be curtailed while alternative treatment and disposal methods are developed and approved, or the costs of operations on the underlying properties may increase, which could reduce cash distributions by the Trust and the value of Trust units.

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

Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners of oil and natural gas properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. Neither the Trustee nor the Trust unitholders have any contractual ability to influence or control the field operations of, and sale of oil and natural gas from, the underlying properties, including underlying properties where Whiting is the operator. Also, the Trust unitholders have no voting rights with respect to the operators of these properties and, therefore, have no managerial, contractual or other ability to influence the activities of the operators of these properties.

The Trust’s NPI may be characterized as an executory contract in bankruptcy, which could be rejected in bankruptcy, thus relieving Whiting from its obligations to make payments to the Trust with respect to the NPI.

Whiting has recorded the conveyance of the NPI in the states where the underlying properties are located in the real property records in each county where these properties are located. The NPI is a non-operating, non-possessory interest carved out of the oil and natural gas leasehold estate, but certain states have not directly determined whether a NPI is a real or a personal property interest. Whiting believes that the delivery and recording of the conveyance should create a fully conveyed and vested property interest under the applicable state’s laws, but certain states have not directly determined whether this would be the result. If in a bankruptcy proceeding in which Whiting becomes involved as a debtor a determination were made that the conveyance constitutes an executory contract and the NPI is not a fully conveyed property interest under the laws of the applicable state, and if such contract were not to be assumed in a bankruptcy proceeding involving Whiting, the Trust would be treated as an unsecured creditor of Whiting with respect to the NPI in the pending bankruptcy proceeding.

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If the financial position of Whiting degrades in the future, Whiting may not be able to satisfy its obligations to the Trust.

Whiting operates approximately 53% of the underlying properties based on the standardized measure of discounted future net cash flows at December 31, 2016. 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 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.

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

Whiting is currently designated as the operator of approximately 53% of the underlying properties based on the standardized measure of discounted future net cash flows at December 31, 2016. However, for the 47% of the underlying properties that it does not operate, Whiting does not have control over normal operating procedures, expenditures or future development relating to such properties. The failure of an operator to adequately perform operations or an operator’s breach of the applicable agreements could reduce production from the underlying properties and the cash available for distribution to Trust unitholders. The success and timing of operational activities on properties operated by others therefore depends upon a number of factors outside of Whiting’s control, including the operator’s decisions with respect to the timing and amount of capital expenditures, the period of time over which the operator seeks to generate a return on capital expenditures, the inclusion of other participants in drilling wells, and the use of technology, as well as the operator’s expertise and financial resources and the operator’s relative interest in the underlying field. Operators may also opt to decrease operational activities following a significant decline in oil or natural gas prices. Because Whiting does not have a majority interest in most of the non-operated properties comprising the underlying properties, Whiting may not be in a position to remove the operator in the event of poor performance. Accordingly, while Whiting has agreed to use commercially reasonable efforts to cause the operator to act as a reasonably prudent operator, it is limited in its ability to do so.

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.

An increase in the differential or decrease in the premium between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price received could reduce cash distributions by the Trust and the value of Trust units.

Oil and natural gas production from the underlying properties generally trades at a discount, but sometimes at a premium, to the relevant benchmark prices, such as NYMEX. A negative difference between the benchmark price and the price received is called a differential and a positive difference is called a premium. The differential and premium may vary significantly due to market conditions, the quality and location of production and other risk factors. Whiting cannot accurately predict oil and natural gas differentials or premiums. Increases in the differential and decreases in the premiums between the benchmark price for oil and natural gas and the wellhead price received could reduce cash distributions by the Trust and the value of the Trust units.

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

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

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

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

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

· In the event the Trust is required to sell the NPI because (i) annual cash proceeds to the Trust from the net profits interest are less than $2.0 million for each of any two consecutive years or (ii) Trust unitholders vote to sell the NPI, Whiting may seek to purchase the NPI from the Trust. Although the Trustee has certain obligations to unitholders in connection with the sale of the NPI, there is likely a limited universe of potential buyers given the terms of the net profits interest and Whiting’s residual interest in the underlying properties.

· 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 the NPI relates. In such an event, the Trust is entitled to receive its proportionate share of the proceeds from the sale attributable to the NPI released.

· The Trust has no employees and is reliant on Whiting’s employees to operate those underlying properties for which Whiting is designated as the operator. Whiting’s employees are also responsible for the operation of other oil and gas properties Whiting owns, which may require a significant portion or all of their time and resources.

The documents governing the Trust generally do not provide a mechanism for resolving these conflicting interests.

The Trust is managed by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.

The business and affairs of the Trust are administered by the Trustee. The voting rights of a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The Trust agreement provides that the Trustee may only be removed and replaced by a vote of the holders of a majority of the outstanding Trust units at a special meeting of Trust unitholders called by either the Trustee or the holders of not less than 10% of the outstanding Trust units. As a result, it may be difficult to remove or replace the Trustee.

Trust unitholders have limited ability to enforce provisions of the NPI.

The Trust agreement permits the Trustee to sue Whiting on behalf of the Trust to enforce the terms of the conveyance creating the NPI. If the Trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of a Trust unitholder would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The Trust agreement expressly limits the Trust unitholders’ ability to directly sue Whiting or any other third party other than the Trustee. As a result, the unitholders are not able to sue Whiting to enforce these rights.

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

Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations under the General Corporation Law of the State of Delaware. Courts in jurisdictions outside of Delaware, however, may not give effect to such limitation.

The operations of the underlying properties may result in significant costs and liabilities with respect to environmental and operational safety matters, which could reduce the amount of cash available for distribution to Trust unitholders.

Significant costs and liabilities can be incurred as a result of environmental and safety requirements applicable to the oil and natural gas exploration, development and production activities of the underlying properties. These costs and liabilities could arise under a

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wide range of federal, regional, state and local environmental and safety laws, regulations, and enforcement policies, which legal requirements have tended to become increasingly strict over time. Numerous governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts on the operations of the underlying properties.

Although President Trump has indicated that he would work to ease regulatory burdens on industry and on the oil and gas sector, including environmental regulations, any executive orders the President may issue or any new legislation Congress may pass with the goal of reducing environmental statutory or regulatory requirements may be challenged in court. In addition, various state laws and regulations (and permits issued thereunder) will be unaffected by federal changes unless and until the state laws and corresponding permits are similarly changed, and any judicial review is completed.

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

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

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

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

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

Climate change legislation or regulations restricting emissions of “greenhouse gases” 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.

In December 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 adopted and implemented regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, as amended (the “CAA”), including rules that limit 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 in January 2011. In  June 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (the

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“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.

In June 2014, the Supreme Court upheld most of the EPA’s GHGs permitting requirements, allowing the agency to regulate the emission of GHGs from stationary sources already subject to the PSD and Title V requirements. Certain of Whiting’s equipment and installations may currently be subject to PSD and Title V requirements and hence, under the Supreme Court’s ruling, may also be subject to the installation of controls to capture GHGs. For any equipment or installation so subject, Whiting may have to incur increased compliance costs to capture related GHGs emissions, which could reduce cash distributions by the Trust and the value of Trust units.

In October 2016, EPA proposed revisions to the rule applicable to GHGs for PSD and Title V permitting requirements. The proposed rule, which would not expand federal GHG permitting requirements, has not been finalized.

The EPA announced in 2015 that it would directly regulate methane emissions from oil and natural gas wells for the first time as part of President Obama’s Climate Action Plan. As part of this strategy, in May 2016, the EPA issued a final rule that updated the New Source Performance Standards to add requirements that the oil and gas industry reduce emissions of greenhouse gases and to cover additional equipment and activities in the oil and gas production chain. The final rule sets emissions limits for methane, which is the principal greenhouse gas emitted by equipment and processes in the oil and gas sector. This rule applies to new, reconstructed and modified processes and equipment.

In accordance with President Obama’s Climate Action Plan, in August 2015, the EPA issued a rule to reduce carbon emissions from electric generating units. The rule, commonly called the “Clean Power Plan,” requires states to develop plans to reduce carbon emissions from fossil fuel-fired generating units commencing in 2022, with the reductions to be fully phased in by 2030. Each state is given a different carbon reduction target, but the EPA expects that, in the aggregate, the overall proposal will reduce carbon emissions from electric generating units by 32% from 2005 levels. States are given substantial flexibility in meeting their emission reduction targets and can generally choose to lower carbon emissions by replacing higher carbon generation, such as coal or natural gas, with lower carbon generation, such as efficient natural gas units or renewable energy alternatives. Several industry groups and states have challenged the Clean Power Plan in the Court of Appeals for the D.C. Circuit, and in February 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan while it is being challenged in court. The Court of Appeals for the D.C. Circuit heard oral arguments on the Clean Power Plan in September 2016, but has not yet issued a decision. President Trump has indicated that he is opposed to the Clean Power Plan, and the new administration could withdraw the rule and potentially repropose it, or seek to invalidate the EPA’s prior determination that GHGs present an endangerment to public health and the environment. Either action is likely to be challenged in court, which could delay implementation of any new rules.

In addition, both houses of Congress have actively 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, GHG 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 that could adversely affect demand for oil, natural gas liquids and natural gas produced. Finally, it should be noted that many scientists have concluded that increasing concentrations of GHGs in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on the Trust’s assets and the amount of cash available for distribution to the Trust unitholders.

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

The demand for qualified and experienced field personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs, completion crews and other oilfield equipment as demand

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for these items has increased along with the number of wells being drilled and completed. 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 and other oilfield goods and services. Additionally, operations on the underlying properties in some instances require supply materials such as CO₂ for production which could become subject to shortage and increasing costs. Shortages of field personnel, drilling rigs, completion crews, equipment, supplies or personnel or price increases could delay or adversely affect the amount of cash available for distribution to the Trust unitholders, or restrict operations on the underlying properties.

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

Whiting previously participated in the formation and initial public offering of Whiting USA Trust I (“Trust I”) on April 30, 2008 and Trust I terminated its NPI effective January 28, 2015 as a result of the contractual volumes being produced and sold from Trust I’s underlying properties. Given the differences in assets comprising the underlying properties, commodity prices, production and development costs, development schedule, operators of the underlying properties and regulatory environment, among other things, the historical results of operations of Whiting USA Trust I should not be relied on as an indicator of how Whiting USA Trust II will perform.

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

If Whiting is notified by a person with whom Whiting is a party to a contract containing a prior reversionary interest that Whiting is required to convey any of the underlying properties to such person or cease production from any well, then Whiting may provide such conveyance with respect to such underlying property or permanently cease production from such well. Such a reversionary interest typically results from the provisions of a joint operating agreement that governs the drilling of wells on jointly owned property and financial arrangements for instances where all owners may not want to make the capital expenditure necessary to drill a new well. The reversionary interest is created because an owner that does not consent to capital expenditures will not have to pay its share of the capital expenditure, but instead will relinquish its share of proceeds from the well until the consenting owners receive payout (or a multiple of payout) of their capital expenditures. In such case, Whiting may request the Trustee to reconvey to Whiting the NPI with respect to any such underlying property or well. The Trust will not receive consideration for any such reconveyance of a portion of the NPI and, any such reconveyance of a portion of the NPI may extend the time it takes 11.79 MMBOE (10.61 MMBOE at the 90% NPI) to be produced from the underlying properties for purposes of the NPI.

The Trust has not requested a ruling from the IRS regarding the tax treatment of ownership of the Trust units. If the IRS were to determine (and be sustained in that determination) that the Trust is not a “grantor trust” for federal income tax purposes, or that the NPI is not properly treated as a production payment (and thus could fail to qualify as a debt instrument) for federal income tax purposes, the Trust unitholders may receive different and potentially less advantageous tax treatment than they anticipated.

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

If the NPI were not treated as a debt instrument, any deductions allowed to an individual Trust unitholder in their recovery of basis in the NPI may be itemized deductions, the deductibility of which would be subject to limitations that may or may not apply depending upon the unitholder’s circumstances.

Neither Whiting nor the Trustee has requested a ruling from the IRS regarding these tax questions, and neither Whiting nor the Trust can assure that such a ruling would be granted if requested or that the IRS will not challenge this position on audit.

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

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

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

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

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

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

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 properties are long-lived, predominately producing properties located primarily in the Permian Basin, Rocky Mountains, Gulf Coast and Mid-Continent regions of the United States. The underlying properties include interests in 1,314 gross (379.4 net) producing oil and natural gas wells located in 47 predominately mature fields with established production profiles in 10 states. As of December 31, 2016, approximately 98.8% of estimated proved reserves attributable to the Trust were classified as proved developed producing reserves and 1.2% were classified as proved developed non-producing reserves. For the year ended December 31, 2016, the net production attributable to the underlying properties was 1,235 MBOE or 3,375 BOE/d. Whiting operates approximately 53% of the underlying properties based on the December 31, 2016 reserve report standardized measure of discounted future net cash flows.

Whiting’s interests in the oil and natural gas properties comprising the underlying properties require Whiting to bear its proportionate share, along with the other working interest owners, of the costs to develop and operate such properties. Many of the properties comprising the underlying propertiesthat are operated by Whiting are burdened by non-working interests owned by third parties androyalty interests retained by the owners of the land subject to the working interests. The royalty interests typically entitle the landowner to receive at least 12.5% of the revenue derived from oil and natural gas production from wells drilled on the landowner’s land, without any deduction for drilling costs or other costs related to production of oil and natural gas. A working interest percentage represents a working interest owner’s proportionate ownership interest in a property in relation to all other working interest owners in that property, whereas a net revenue interest is a working interest owner’s percentage of production and revenues, after reducing such interest by the percentage of burdens on production such as royalties and overriding royalties.

The NPI entitles the Trust to receive 90% of the net proceeds from the sale of at least 11.79 MMBOE (10.61 MMBOE at the 90% NPI) of production from the underlying properties.  As of December 31, 2016, on a cumulative accrual basis 6.89 MMBOE (65%) of the 10.61 MMBOE attributable to the NPI have been produced and sold or divested. The remaining minimum reserve balance of 3.72 MMBOE (at the 90% NPI) is projected to be produced by July 31, 2023, based on the Trust’s year-end 2016reserve 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 of those assumptions and their inherent risks. The rate of future production cannot be predicted with certainty, and the Trust’s 10.61 MMBOE may be produced before or after thecurrently projected date. The proved reserves attributable to the underlying properties include all proved reserves expected to be economically produced during the remaining full life of the properties, whereas the Trust is entitled to only receive 90% of the net proceeds from the sale of production of oil, natural gas and natural gas liquids attributable to the underlying properties during the term of the NPI.

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

In general, the producing wells to which the underlying properties relate have established production profiles. Based on the reserve report, annual production from the underlying properties is expected to decline at an average year-over-year rate of approximately 12.1% for oil and 15.4% for gas from 2017through the estimated July 31, 2023 NPI termination date, assuming no additional developmental drilling or investments other than those assumed in the year-end reserve report. However, cash distributions, if any, to unitholders may decline at a faster rate than the rate of production due to fixed and semi-variable costs attributable to the underlying properties or if future development is delayed, reduced, or cancelled.

Reserves

As of December 31, 2016, 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, 2016 based on average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-

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of-the-month price for each month within the 12-month period ended December 31, 2016)  attributable to (i) the Trust based on the term of its NPI,and (ii) the underlying properties on a full economic life basis (dollars in thousands):

	Whiting USA Trust II(3)				Underlying Properties(4)
	(90% NPI through July 2023)(5)				(100% Full Economic Life)
	Oil(6) (MBbl)	Natural Gas (Mcf)	MBOE		Oil(6) (MBbl)	Natural Gas (Mcf)	MBOE
Proved reserves(1):
Developed	3,257	2,764		3,718	6,564	4,803		7,365
Undeveloped	-	-		-	-	-		-
Total proved—December 31, 2016	3,257	2,764		3,718	6,564	4,803		7,365
Standardized measure(2)			$	20,979			$	32,209

____________

(1) Oil and gas reserve quantities have been derived from NYMEX oil and gas prices of $42.75 per Bbl and $2.49 per MMBtu, respectively, which are calculated using an average of the first-day-of-the month price for each month within the 12 months ended December 31, 2016, pursuant to current SEC and FASB guidelines. The average NYMEX oil and gas prices for the month of January 2017 were $52.61 per Bbl and $3.68 per MMBtu, respectively.  

(2) Standardized measure of discounted future net cash flows as of December 31, 2016. 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.

(3) The Trust’s estimated proved reserves as of December 31, 2016 on a 90% basis were 3,718MBOE, 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.

(4) The reserves attributable to the underlying properties include all reserves expected to be economically produced during the life of the properties, whereas the Trust is entitled to only receive 90% of the net proceeds from the sale of production of oil, natural gas and natural gas liquids attributable to the underlying properties during the term of the NPI.

(5) The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when minimum volumes of 10.61 MMBOE attributable to the NPI have been produced from the underlying properties and sold, or (b) the sale of the net profits interest. The December 31, 2016 reserve report projects that the underlying properties will produce the Trust’s minimum volumes by July 31, 2023.

(6) Oil includes natural gas liquids.

The above table does not include any proved undeveloped reserve quantities as of December 31, 2016 primarily because the underlying properties consist of mature producing properties that are essentially fully developed. While technical studies have identified an insignificant number of drilling locations that meet the criteria of proved undeveloped reserves, such locations are not reflected in the December 31, 2016 reserve report because they are not economic to develop based on the year-end reserve report commodity prices.

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 and development expenditures required to produce the proved reserves as of December 31, 2016. 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, 2016to December 31, 2016, 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 2016,  revisions to previous estimates increased proved reserves by a net amount of 2  MBOE. Included in these revisions were (i) 472 MBOE of net upward adjustments attributable to reservoir analysis and enhanced well performance and (ii) 470 MBOE of downward adjustments caused by lower oil and gas pricing incorporated into the Trust’s reserve estimates at December 31, 2016 as compared to December 31, 2015.

Preparation of reserves estimates. Whiting has advised the Trustee that it maintains adequate and effective internal controls over the reserve estimation process as well as the underlying data upon which reserve estimates are based.The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data.All field and

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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 (2013)  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 office to review field performance.Following this review 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.Our primary contact at CG&A isMr. W. Todd Brooker, Senior Vice President. Mr. Brooker 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. Brooker.

Whiting’s Vice President of Reservoir Engineering and Acquisitions is responsible for overseeing the preparation of the reserves estimates.He has over32 years of acquisition and reservoir engineering experience,  holds a Bachelor’s degree in Petroleum Engineering from the Colorado School of Mines and is a member of the Society of Petroleum Engineers.

As noted above, the current reserve report projects that 10.61 MMBOE attributable to the 90% NPI will be produced from the underlying properties by July 31, 2023. The exact rate of production attributable to the underlying properties cannot be accurately predicted as numerous uncertainties are inherent in estimating reserve volumes and values, and such estimates are subject to change as additional information becomes available. The quantity of reserves actually recovered and the timing of their production may vary significantly from these estimates.

Producing Acreage and Well Counts

For the following data, “gross” refers to the total wells or acres in the oil and natural gas properties in which Whiting owns a working interest and “net” refers to gross wells or acres multiplied by the percentage working interest owned by Whiting and in turn attributable to the underlying properties. Although many of Whiting’s wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas production.

The underlying properties are mainly interests in developed properties located in oil and natural gas producing regions outlined in the chart below. The following is a summary of the number of fields and approximate acreage of these properties by region at December 31, 2016.

	Number of	Developed Acreage		Undeveloped Acreage		Total Acreage
Region	Fields	Gross	Net	Gross	Net	Gross	Net
Permian Basin	17	25,356	19,740	4,800	2,913	30,156	22,653
Rocky Mountains	14	25,383	10,291	-	-	25,383	10,291
Gulf Coast	8	11,257	4,382	470	153	11,727	4,535
Mid-Continent	8	2,886	1,607	80	72	2,966	1,679
Total	47	64,882	36,020	5,350	3,138	70,232	39,158

The following is a summary of the producing wells on the underlying properties as of December 31, 2016:

	Operated Wells		Non-Operated Wells		Total Wells
	Gross	Net	Gross	Net	Gross	Net
Oil	287	258.1	951	90.7	1,238	348.8
Natural gas	31	26.2	45	4.4	76	30.6
Total	318	284.3	996	95.1	1,314	379.4

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The following is a summary of the number of developmental wells drilled on the underlying properties during the last three years. A dry well is an exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil orgas 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 wasoneexploratory well in the process of being drilled as part of the Keystone South field farm-out as of December 31, 2016, and the farm-out partner is responsible for 100% of the capital costs for this well. No other wells were in process of being drilled as of December 31, 2016.

	Year Ended December 31,
	2016		2015		2014
	Gross	Net	Gross	Net	Gross	Net
Productive
Oil wells(1)	3	0.02	10	0.08	8	0.27
Natural gas wells	-	-	-	-	2	0.03
Dry	-	-	-	-	-	-
Total	3	0.02	10	0.08	10	0.30

____________

(1) During 2016, a unitization occurred in the Garland field which resulted in an additional nine gross (1.76 net) oil wells being added to the Trust that were previously drilled.

Oil and Natural Gas Production

The following table shows the sales volumes, average sales prices per Bbl of oil and Mcf of natural gas produced and the production costsper BOE for the underlying properties. Sales volumes for natural gas liquids are included with oil sales since they were not material.

	Year Ended December 31,
	2016		2015		2014
Net sales volumes:
Oil production (MBbl)(1)		1,002		1,113		1,229
Natural gas production (MMcf)		1,397		1,795		2,141
Total production (MBOE)		1,235		1,412		1,586
Average daily production (MBOE/d)		3.4		3.9		4.3
Garland field sales volumes(2):
Oil production (MBbl)(1)		154		165		169
Natural gas production (MMcf)		47		60		57
Total production (MBOE)		162		175		178
Rangely field sales volumes(2):
Oil production (MBbl)(1)		162		164		181
Natural gas production (MMcf)		-		-		-
Total production (MBOE)		162		164		181
Average sales prices:
Oil (per Bbl)(1)	$	35.22	$	41.01	$	80.86
Natural gas (per Mcf)	$	2.48	$	2.94	$	5.39
Average production costs:
Production costs per BOE(3)	$	24.55	$	25.63	$	28.32

____________

(1) Oil includes natural gas liquids.

(2) The Garland and Rangely fields were the only fields that contained 15% or more of the total proved reserve volumes of the underlying properties as of December 31, 2016. The Garland field was the only field that contained 15% or more of the total proved reserve volumes of the underlying properties as of December 31, 2015. The Rangely field was the only field that contained 15% or more of the total proved reserve volumes of the underlying properties as of December 31, 2014.

(3) Production costs reported above exclude from lease operating expenses ad valorem taxes of $1.4million ($1.15/BOE), $1.6 million,  ($1.10/BOE),  and $2.7 million  ($1.68/BOE),for the years ended December 31, 2016,  2015 and 2014, respectively.

There are certain of the Trust’s wells that are included ineightseparate enhanced oil recovery waterflood projects, which include both secondary (waterflood) and tertiary (CO2 injection) recovery efforts.Aggregate production from such enhanced oil recovery fields

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averaged 1,327BOE/d during 2016 or 39%of 2016 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

Other than the underlying properties’ commitment of 11.79 MMBOE to the Trust pursuant to the terms of the NPI, neither the Trust nor the underlying properties are committed to deliver fixed quantities of oil or natural gas in the future under existing contracts or agreements.

Major Producing Areas

The underlying properties are located in several major onshore producing basins in the continental United States. However, even this broad distribution may not provide protection against regional trends that may negatively impact production or prices. Based on the standardized measure of discounted future net cash flows at December 31, 2016, approximately 53% of these properties were operated by Whiting. Based on annual 2016production attributable to the underlying properties, approximately 81%of production was crude oil and natural gas liquids and 19%of production was natural gas. These properties are located in mature fields and have established production profiles. However, production and distributions to the Trust will continue to decline over time.

Permian Basin Region. The Permian Basin region is one of the major hydrocarbon producing provinces in the continental United States. The underlying properties in the Permian Basin region are located in Texas and New Mexico. These properties consist of 17 fields, of which Whiting operates wells in 12. The major fields in this region, include the Keystone South field that produces from the Clear Fork, Wichita Albany and Ellenberger zones; the Martin field that produces from the Clear Fork and Wichita Albany zones; the DEB field that produces from the Wolfcamp zone; the Signal Peak field that produces from the Wolfcamp zone; and the Sable field that produces from the San Andres zone. For the year ended December 31, 2016, the net production attributable to the underlying properties in the region was 527.1 MBOE or 1.4 MBOE/d.

Rocky Mountains Region. The underlying properties in the Rocky Mountains region are located in Colorado, Wyoming, North Dakota and Montana. These properties consist of 14 fields of which Whiting operates wells in four.  The Trust’s NPI does not include any of Whiting’s interests in the Bakken and Three Forks formations. The major fields in this region include the Rangely fieldthat produces from the Weber Sand zone; the Garland field that produces from the Madison and Tensleep zones; the Cedar Hills field that produces from the Red River zone; and the Whiting-operated Torchlight field that produces from the Madison and Tensleep zones. For the year ended December 31, 2016, the net production attributable to the underlying properties in the region was 527.9MBOE or 1.5MBOE/d.

Gulf Coast Region. The underlying properties in the Gulf Coast region are located in Texas and Mississippi. These properties consist of eight onshore fields, and Whiting operates wells in four.  The major field in this region is the Whiting-operated Lake Como field located in Mississippi that produces from the Smackover formation. For the year ended December 31, 2016, the net production attributable to the underlying properties in the region was 149.3MBOE or 0.4MBOE/d.

Mid-Continent Region. The underlying properties in the Mid-Continent region are located in Michigan, Arkansas, Oklahoma and Texas. These properties consist of eightfields of which Whiting operates wells in three.  The major field in this region is the Whiting operated Wesson field located in Arkansasthat produces from the Hogg Sand zone. For the year ended December 31, 2016, the net production attributable to the underlying properties in the region was 31.0MBOE or 0.1MBOE/d.

Abandonment, Sale, and Farm-out of Underlying Properties

Any operator of the underlying properties, includingWhiting, has the right to abandon its interest in any well or property comprising a portion of the underlying properties if, in its opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities. To reduce the potential conflict of 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 these properties if they were not burdened by the NPI, and Whiting has agreed to use commercially reasonable efforts to cause the other operators to operate these properties in the same manner. However, Whiting’s ability to cause other operators to take certain actions is limited. For the years ended December 31, 2016,  2015 and2014, there werefive,  fiveandfourgross wells, respectively, that were plugged and abandoned on the underlying properties, based on the determination that such wells were no longer economic to operate.

Divestitures. Whiting may, without the consent of the Trust unitholders, require the Trust to sell the NPI associated with any well or lease that accounts for less than or equal to 0.25% of the total production from the underlying properties in the prior 12 months,

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provided that the NPI covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the Trust of $1.0 million. These releases will be made only in connection with a sale by Whiting of the relevant underlying properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such portion of the NPI. Any net sales proceeds paid to the Trust are distributable to Trust unitholders for the quarter in which they are received.

During 2016, Whiting completed the sale of three shut-in oil and gas wells (effective for all cost and sales proceeds, if any, beginning September 1, 2016) for a total purchase price of $65,000($58,500to the 90% net profits interest). The divested properties were located within the Chester and Blair fields in Michigan and had no remaining proved reserves since these wells were being prepared for plugging and abandonment operations by Whiting.In addition, during 2015 Whiting completed the sale of certain producing oil and gas wells for a purchase price of $0.4 million ($0.3 million to the 90% net profits interest). The divested properties included nine wells located within Cooks Peak field in North Dakota, which had proved reserves of 18.14 MBOE (16.32 MBOE to the 90% net profits interest).No such sales of oil and gas wells occurred during the year ended December 31, 2014.

Farm-out agreements. For the underlying properties for which Whiting is the designated operator, it may enter into farm-out, operating, participation and other similar agreements with respect to the property. Whiting may enter into any of these agreements without the consent or approval of the Trustee or any Trust unitholder. Whiting has entered into two farm-out arrangements in an effort to develop the underlying properties without incurring any additional capital expenditures for the Trust (other than those capital expenditures already contemplated in the reserve report).

During April 2016, Whiting Oil and Gas entered into a farm-out agreement with a third-party partner, which agreement covers 5,127 gross acres within the Keystone South field in Winkler County, Texas. The underlying properties have a 100% working interest in the leases included in this arrangement. The agreement provides the partner with the option, but not the obligation, to drill one well in each of the eight leasehold sections subject to the farm-out, whereby the partner will pay 100% of the capital costs for the well to earn a 75% working interest, which results in the underlying properties retaining (i) a 25% working interest and (ii) an overriding royalty interest equal to the difference between 25% and the lease burdens of record, without incurring any capital costs for these wells. Upon completion of one well in each section pursuant to the terms of the agreement, the partner has the option to drill an additional 15 wells where the partner is required to pay 85% of the capital costs for their 75% working interest, and the Trust would be responsible for 13.5%, subject to the average annual capital expenditure amount limitation as described in the “Computation of Net Proceeds” section in Item I, of the remaining capital costs at the 90% NPI. The partner drilled the first well under this farm-out arrangement during December 2016 (which was completed in January 2017) however, the partner has no obligation to drill any additional wells.

Additionally, in February 2017, Whiting Oil and Gas entered into another farm-out agreement with a third party partner, which agreement covers 9,470 gross acres within the Signal Peak field in Howard County, Texas. The agreement provides the partner with the option, but not the obligation, to drill one well in each unit subject to the farm-out (which unit size is determined by the lateral well length), whereby the partner will pay 100% of the underlying properties capital costs for the well to earn 75% of the underlying properties working interest in the leases, which results in the underlying properties retaining (i) 25% of its original working interest and (ii) an overriding royalty interest equal to the difference between 25%and the lease burdens of record, without incurring any capital costs for these wells. Upon completion of one well in each unit pursuant to the terms of the agreement, the partner has the option to drill an additional 12 wells where the partner is required to pay 85% of the underlying properties capital costs for their 75% of the underlying properties working interest, and the Trust would be responsible for 13.5%, subject to the average annual capital expenditure amount limitation as described in the “Computation of Net Proceeds” section in Item I, of the underlying properties remaining capital costs at the 90% NPI. This farm-out agreement will terminate if no such drilling has commenced on or before November 30, 2017.

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.

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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 and other burdens on production, express and implied, under oil and natural gas leases;

· overriding royalties, production payments and similar interests and other burdens on production created by Whiting or its predecessors in title;

· a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect these properties or Whiting’s title thereto;

· liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;

· pooling, unitization and communitization agreements, declarations and orders;

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

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

· rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the underlying properties and the NPI therein.

Whiting has informed the Trustee that Whiting believes the burdens and obligations affecting the oil and natural gas properties comprising the underlying properties are conventional in the industry for similar properties. Whiting also has informed the Trustee that Whiting believes that the existing burdens and obligations do not, in the aggregate, materially interfere with the use of the underlying properties and do not materially adversely affect the value of the NPI.

At the time of its acquisitions of the underlying properties, Whiting undertook a title examination of these properties. As such, Whiting has informed the Trustee that Whiting believes its title to the underlying properties is, and the Trust’s title to the net profits interest is, good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions as are not so material to detract substantially from the use or value of such properties or royalty interests.

Net profits interests are non-operating, non-possessory interests carved out of the oil and natural gas leasehold estate, but some jurisdictions have not directly determined whether a NPI is a real or a personal property interest. Whiting has recorded the conveyance of the NPI in the relevant real property records of all applicable jurisdictions. Whiting has informed the Trustee that Whiting believes the delivery and recording of the conveyance creates a fully conveyed and vested property interest under the applicable state’s laws, but because there is no direct authority to this effect in some jurisdictions, this may not always be the result. Whiting has also informed the Trustee that Whiting believes that it is possible the NPI may not be treated as a real property interest under the laws of certain of the jurisdictions where the underlying properties are located. Whiting has also informed the Trustee that Whiting believes that, if,during the term of the NPI, Whiting becomes involved as a debtor in a bankruptcy proceeding, the NPI relating to the underlying properties in most, if not all, of the jurisdictions should be treated as a fully conveyed property interest. In such a proceeding, however, a determination could be made that the conveyance constitutes an executory contract and the NPI is not a fully conveyed property interest under the laws of the applicable jurisdiction, and if such contract were not to be assumed in a bankruptcy proceeding involving Whiting, the Trust would be treated as an unsecured creditor of Whiting with respect to the 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 UnitholderMatters and Issuer Purchases of Equity Securities

The Trust units commenced trading on the New York Stock Exchange on March 23, 2012 under the symbol “WHZ” and were delisted from the New York Stock Exchange on January 6, 2016.The Trust units transitioned to the OTC, operated by OTC Markets Group, effective with the open of trading on January 7, 2016 under the symbol “WHZT”.

Each quarter, the Trustee determines the amount of funds available for distribution, if any, to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the NPI and other sources (such as interest earned on any amounts reserved by the Trustee) that quarter, over the Trust’s liabilities for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities. Quarterly cash distributions during the term of the Trust are made by the Trustee generally no later than 60 days following the end of each quarter (or the next succeeding business day) to the Trust unitholders of record on the 50th day following the end of each quarter.

The high and low sales prices per unit, distributable income and distributable income per unit for each quarter in 2016 and 2015were as follows:

	Price Range				Distributable		Distributable
	High		Low		Income(1)		Income per Unit
Year Ended December 31, 2016
First quarter (January 1 through March 31)	$	0.72	$	0.10	$	-	$	-
Second quarter (April 1 through June 30)	$	0.88	$	0.04	$	-	$	-
Third quarter (July 1 through September 30)	$	0.90	$	0.62	$	-	$	-
Fourth quarter (October 1 through December 31)	$	1.15	$	0.70	$	1,199	$	0.065170
Year Ended December 31, 2015
First quarter (January 1 through March 31)	$	8.47	$	4.60	$	6,022	$	0.327255
Second quarter (April 1 through June 30)	$	6.21	$	2.55	$	236	$	0.012803
Third quarter (July 1 through September 30)	$	2.80	$	1.02	$	2,919	$	0.158632
Fourth quarter (October 1 through December 31)	$	2.04	$	0.69	$	183	$	0.010003

____________

(1) Dollars in thousands.

At December 31, 2016, the 18,400,000 units outstanding were held by twounitholders of record.

Subsequent to year-end, onMarch 1, 2017, a distribution of $0.063784 per Trust unit was paid to the Trust unitholders of record on February 19, 2017 (which resulted in an effective record date of February 17, 2017). This aggregate distribution to all Trust unitholders consisted of net cash proceeds of $1.5 million paid by Whiting to the Trust, less a provision of $0.3 million for estimated Trust expenses and $2,358 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 2016.

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Item 6. Selected Financial Data

The Trust was formed on December 5, 2011, however,the conveyance of the NPI did not occur until March 28, 2012. As a result, the Trust did not recognize any income or make any distributions until the second quarter of 2012. The following table sets forth selected data for the Trust for the yearsended December 31, 2016, 2015, 2014,  2013and 2012 and as of December 31, 2016, 2015, 2014, 2013 and 2012based on the Trust’s audited financial statements (in thousands, except distributable income per unit and Trust units outstanding data):

	Year Ended December 31,
	2016		2015		2014		2013			2012
Income from net profits interest	$	1,548	$	10,161	$	52,362	$	54,485	$	49,023
Distributable income	$	1,199	$	9,360	$	51,389	$	53,550	$	48,015
Distributable income per unit	$	0.065170	$	0.508693	$	2.792906	$	2.910335	$	2.609500

	December 31,
	2016		2015		2014		2013			2012
Trust corpus	$	23,929	$	30,966	$	57,789	$	144,990	$	171,355
Total assets at year-end	$	24,113	$	31,245	$	58,079	$	145,211	$	171,516
Trust units outstanding		18,400,000		18,400,000		18,400,000		18,400,000		18,400,000

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

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

Overview and Trust Termination

The Trust 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 31, 2014 (which hedging effects impacted the February 2015 distribution and ceased thereafter). The NPI entitles the Trust to receive 90% of the net proceeds from the sale of production from the underlying properties.

Oil and gas prices historically have been volatile and may fluctuate widely in the future. The table below highlights these price trends by listing quarterly average NYMEX crude oil and natural gas prices for the periods indicated through December 31, 2016. The 2016 NPI distributions are mainly affected, however, by October 2015 through September 2016 oil prices and September 2015 through August 2016 natural gas prices.

	2014								2015								2016
	Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4
Crude oil	$	98.62	$	102.98	$	97.21	$	73.12	$	48.57	$	57.96	$	46.44	$	42.17	$	33.51	$	45.60	$	44.94	$	49.33
Natural gas	$	4.93	$	4.68	$	4.07	$	4.04	$	2.99	$	2.61	$	2.74	$	2.17	$	2.06	$	1.98	$	2.93	$	2.98

Oil prices have fallen significantly since reaching highs of over $105.00 per Bbl in June 2014, dropping below $27.00 per Bbl in February 2016. Natural gas prices have also declined from over $4.80 per MMBtu in April 2014 to below $1.70 per MMBtu in March 2016.  Although oil and natural gas prices have begun to recover from the lows experienced during the first quarter of 2016, forecasted prices for both oil and natural gas remain low. Lower oil and gas prices on production from the underlying properties could cause the following: (i) a reduction in the amount of net proceeds to which the Trust is entitled; and (ii) a reduction in the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties causing an extension of the length of time required to produce 11.79 MMBOE (10.61 MMBOE at the 90% NPI). If prices remain at current levels, the amount of net proceeds to which the Trust is entitled is likely to be substantially lower than the net proceeds the Trust has received and distributed to Trust unitholders in the past. All costless collar hedge contracts Whiting entered into, and in turn conveyed to the Trust, terminated as of December 31, 2014 (which hedging effects extended through the February 2015 distribution to unitholders) and no additional hedges are allowed to be placed on the Trust assets. Consequently, there areno further cash settlement gains or losses on commodity derivatives for inclusion in the Trust’s computation of net proceeds (or net losses, as the case may be), and the Trust therefore has increased exposure to oil and natural gas price volatility.

Trust termination.The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE (10.61 MMBOE to the 90% net profits interest) have been produced from the underlying properties and sold, which is estimated to be July 31, 2023 based on the Trust’s year-end 2016 reserve report or (b) the sale of the net profits interest. The Trust is required to sell the NPI and liquidate if cash proceeds to the Trust from the net profits interest are less than $2.0 million for each of any two consecutive years. During the year ended December 31, 2016, the Trust received cash proceeds of $1.9 million from the net profits interest. The Trust also received cash proceeds of $1.5 million from the NPI during the first calendar quarter of 2017. Therefore, if cash proceeds to the Trust from the net profits interest are less than $0.5 million over the remaining three calendar quarters of 2017, the Trust will be required to sell the NPI and terminate. After the termination of the Trust, it will pay no further distributions.

Since the assets of the Trust are depleting assets, a portion of each cash distribution paid, if any, on the Trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment or yield. As a result, the market price of the Trust units will decline to zero at termination of the Trust. As of December 31, 2016, ona cumulative accrual basis, 6.89 MMBOE (65%) of the 10.61 MMBOE attributable to the NPI have been produced and soldor divested. The remaining minimum reserve quantities are projected to be produced byJuly 31, 2023, based on the Trust’s reserve report as of December 31, 2016. Accordingly, the Trust’s remaining reserves attributable to the 90% NPI were estimated to be 3.72 MMBOE as ofDecember 31, 2016.  For additional discussion relating to the assumptions underlying the estimated date when 11.79 MMBOE (10.61 MMBOE at the 90% NPI) will be produced and sold from the underlying properties,  see “Description of the Underlying Properties” in Item 2 of this Annual Report on Form 10-K.

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

Capital Expenditure Activities

The primary goal of the planned capital expenditures relative to the underlying properties is to mitigatea portion of the natural decline in production from producing properties. The underlying properties have a capital expenditure budget per the reserve report of $12.3 million estimated to be spent over the remainingsix years and seven months. No assurance can be given, however, that any such expenditures will be made, or if made,they will result in production in commercially paying amounts, if any. With respect to the underlying properties, Whiting expects, but is not obligated, to implement the development strategies described below relative to each of the following regions. With respect to fields for which Whiting is not the operator, Whiting will have limited control over the timing and amount of capital expenditures relative to such fields. Please read “Risk factors — Whiting has limited control over activities on the underlying properties that Whiting does not operate, which could reduce production from the underlying properties, increase capital expenditures and reduce cash available for distribution to Trust unitholders.” Information relating to planned capital expenditures on fields for which Whiting is not the operator represent Whiting’s most recent understanding of the planned expenditures and activities of the operator thereof.

In an effort to develop the underlying properties without incurring any additional capital expenditures for the Trust (other than those capital expenditures already contemplated in the reserve report), Whiting Oil and Gas entered into a farm-out agreement during April 2016, which agreement covers 5,127 gross acres within the Keystone South field in Winkler County, Texas. The underlying properties have a 100% working interest in the leases included in this arrangement. The agreement provides the third-party partner with the option, but not the obligation, to drill one well in each of the eight leasehold sections subject to the farm-out, whereby the partner will pay 100% of the capital costs for the well to earn a 75% working interest, which results in the underlying properties retaining (i) a 25% working interest and (ii) an overriding royalty interest equal to the difference between 25% and the lease burdens of record, without incurring any capital costs for these wells. Upon completion of one well in each section pursuant to the terms of the agreement, the partner has the option to drill an additional 15 wells where the partner is required to pay 85% of the capital costs for their 75% working interest, and the Trust would be responsible for 13.5%, subject to the average annual capital expenditure amount limitation described below, of the remaining capital costs at the 90% NPI. The partner drilled the first well under this farm-out arrangement during December 2016 (which was completed in January 2017) however, the partner has no obligation to drill any additional wells.

Additionally, in February 2017, Whiting Oil and Gas entered into another farm-out agreement, which agreement covers 9,470gross acres within the Signal Peak field in Howard County, Texas. The agreement provides the third-party partner with the option, but not the obligation, to drill one well in each unit subject to the farm-out (which unit size is determined by the lateral well length), whereby the partner will pay 100% of the underlying properties capital costs for the well to earn 75% of the underlying properties working interest in the leases, which results in the underlying properties retaining (i) 25% of its original working interest and (ii) an overriding royalty interest equal to the difference between 25% and the lease burdens of record, without incurring any capital costs for these wells. Upon completion of one well in each unit pursuant to the terms of the agreement, the partner has the option to drill an additional 12 wells where the partner is required to pay 85% of the underlying properties capital costs for their 75% of the underlying properties working interest, and the Trust would be responsible for 13.5%, subject to the average annual capital expenditure amount limitation described below,of the underlying properties remaining capital costs at the 90% NPI. This farm-out agreement will terminate if no such drilling has commenced on or before November 30, 2017.

During each twelve-month period beginning on the later to occur of (1) December 31, 2017 and (2) the time when 8.24 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 7.41 MMBOE attributable to the 90% NPI) (in either case, the “capital expenditure limitation date”), the sum of the capital expenditures and amounts reserved for approved capital expenditure projects for such twelve-month period may not exceed the average annual capital expenditure amount. The “average annual capital expenditure amount” means the quotient of (x) the sum of the capital expenditures and amounts reserved for approved capital expenditure projects with respect to the three twelve-month periods ending on the capital expenditure limitation date, divided by (y) three. Commencing on the capital expenditure limitation date and each anniversary of the capital expenditure limitation date thereafter, the average annual capital expenditure amount will be increased by 2.5% to account for expected increased costs due to inflation.

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The following table summarizes the underlying properties’planned capital expenditures per the reserve reportfor 2017 through the NPI termination date, which is currently estimated to be July 31, 2023:

	2017 - 2023 Planned Capital Expenditures
	(in millions)		Gross Wells	Net Wells
Rocky Mountains Region:
Rangely field — CO2 and maintenance capital	$	8.6	-	-
Garland field — maintenance capital		3.1	-	-
Total Rocky Mountains Region	$	11.7	-	-
Permian Basin Region:
DEB field — recompletions	$	0.6	1	1.0
Total Permian Basin Region	$	0.6	1	1.0
Total(1)	$	12.3	1	1.0

____________

(1) The planned capital expenditures attributable to the Trust’s 90% net profits interest are $11.1 million.

Rocky Mountains Region.  The Rangely field, operated by Chevron Corporation, is located in Rio Blanco County, Colorado. This field was discovered in 1931 with development drilling commencing in 1943. The field is currently producing under the tertiary recovery process of CO2 injection. The underlying properties include a 4.6% working interest in the Rangely Weber Sand Unit. Capital is expended each year to purchase CO2 for injection in the field. According to information provided by the operator, theestimated capital expendituresallocated to the underlying properties’ interestare$1.4million for 2017 and then $1.3 million per year for 2018 through the estimated termination of the NPI. Such capital costsare comprised mainly of CO2 purchases andplant and equipment expenditures. Although Whiting is not aware of any other development plans by Chevron or other operators of the underlying properties in this region, these operators may propose capital expenditures in the future. Additionally, although Whiting has not identified any future capital expenditures for the Whiting operated fields in the Rocky Mountains region at this time, further study or offsetting drilling activity may result in capital expenditures in the future.

Whiting owns a non-operated working interest in the Garland field located in Big Horn County, Wyoming, which produces from the Madison and Tensleep zones. According to information provided by the operator, the estimated capital expenditures allocated to the underlying properties’ interest are $0.6 million per year through 2021 related to plant and equipment expenditures. Although Whiting is not aware of any other development plans by this operator or other operators of the underlying properties in this region, these operators may propose capital expenditures in the future.

Permian Basin Region.Whiting operates the DEB field in Gaines County, Texas, which produces from the Wolfcamp zone. Whiting plans to recomplete one well from the currently completed zone to another zone expected to be productive in the wellbore. This recompletion is scheduled to be performed in 2018 when the currently producing zones reach their economic limit. The capital expenditures necessary to perform this recompletion are estimated at approximately $0.6 million allocated to the underlying properties’ interest. Although Whiting has not identified future capital expenditures for any other operated fields in the Permian Basin at this time, further study or offsetting development activity may result in additional capital expenditures in the future.Additionally, although Whiting is not aware of any other development plans by other operators of the underlying properties in the Permian Basin, these operators may propose capital expenditures in the future.

Other Regions.Although Whiting has not identified any future capital expenditures for itsoperated fields in the Gulf Coast and Mid-Continent regionsat this time, further study or offsetting development activity may result in additional capital expenditures in the future. Additionally, although Whiting is not aware of any development plans by other operators of the underlying properties in these regions, operators may propose capital expenditures in the future.

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Results of Trust Operations

The following is a summary of income from net profits interest and distributable income received by the Trust for the years endedDecember 31, 2016,  2015 and 2014consisting of the February, May, August and November distributions, or net losses as the case may be, for each respective year(dollars in thousands, except per Bbl, per Mcf and per BOE amounts):

Trust Results
	Year Ended December 31,
	2016			2015			2014
Sales volumes:
Oil from underlying properties (MBbl)(1)		1,028	(4)		1,125	(5)		1,212	(6)
Natural gas from underlying properties (MMcf)		1,522	(4)		1,875	(5)		2,247	(6)
Total production (MBOE)		1,282			1,437			1,586
Average sales prices:
Oil (per Bbl)(1)	$	33.75		$	48.91		$	86.81
Effect of oil hedges on average price (per Bbl)(2)		-			0.88			-
Oil net of hedging (per Bbl)	$	33.75		$	49.79		$	86.81
Natural gas (per Mcf)(3)	$	2.15		$	3.20		$	5.48
Cost metrics:
Lease operating expenses (per BOE)	$	24.26		$	29.14		$	27.86
Production tax rate (percent of total revenues)		5.1	%		5.1	%		5.2	%
Revenues:
Oil sales(1)	$	34,706	(4)	$	55,006	(5)	$	105,189	(6)
Natural gas sales		3,278	(4)		6,005	(5)		12,307	(6)
Total revenues		37,984			61,011			117,496
Costs:
Lease operating expenses		31,101			41,873			44,192
Production taxes		1,941			3,091			6,124
Development costs		3,222			5,746			8,999
Cash settlements on commodity derivatives(2)		-			(989)			-
Total costs		36,264			49,721			59,315
Net proceeds		1,720			11,290			58,181
Net profits percentage		90	%		90	%		90	%
Income from net profits interest		1,548			10,161			52,362
Proceeds from sale of oil and gas properties		389			-			-
Provision for estimated Trust expenses		(728)			(790)			(950)
Montana state income tax withheld		(10)			(11)			(23)
Distributable income	$	1,199		$	9,360		$	51,389

____________

(1) Oil includes natural gas liquids.

(2) As discussed in “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of this Annual Report on Form 10-K,all costless collar hedge contracts terminated as of December 31, 2014 (which hedging effects extended through the quarterly payment period covered by the February 2015 distribution to unitholders), and no additional hedges are allowed to be placed on Trust assets. Consequently, there are no further cash settlements on commodity hedges, and the Trust will have increased exposure to oil and natural gas price volatility.

(3) The average sales price of natural gas for the gas production months within the year ended December 31, 2014 exceeded the average NYMEX gas prices for those same months within the period due to the “liquids rich” content of a portion of the natural gas volumes produced by the underlying properties. While the gas volumes produced by the underlying properties during the years ended December 31, 2016 and 2015 are still “liquids rich”, such liquids content did not result in a premium to the NYMEX natural gas price due to the decline in liquids realized sales prices.

(4) Oil and gas sales volumes and related revenues for the year ended December 31, 2016 (consisting of the February 2016 and May 2016 net losses and August 2016and November 2016 distributions) generally represent crude oil production from October2015 through September2016 and natural gas production from September2015 through August2016.

(5) Oil and gas sales volumes and related revenues for the year ended December 31, 2015 (consisting of Whiting’s February2015, May2015, August 2015and November 2015 distributions to the Trust) generally represent crude oil production from October 2014 through September 2015 and natural gas production from September 2014 through August 2015.

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(6) Oil and gas sales volumes and related revenues for the year ended December 31, 2014 (consisting of Whiting’s February 2014, May 2014, August 2014 and November 2014 distributions to the Trust) generally represent crude oil production from October 2013 through September 2014 and natural gas production from September 2013 through August 2014.

Comparison of Results of the Trust for the Years Ended December 31, 2016 and 2015

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 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 anddevelopment costsas follows:

Revenues. Oil and natural gas revenues were $23.0 million (or 38%) lower in 2016  compared to 2015.  Sales revenue is a function of average commodity prices realized and oil and gas volumes sold.  The decline in revenue between periods was due to significantly lower realized oil and natural gas prices, as well as lower oil and natural gas production volumes. The average sales price realized decreased for crude oil (before the effects of hedging)and natural gas by 31% and 33%, respectively, between periodsdue to lower NYMEX oil and natural gas prices. Crude oil production volumes declined by 97 MBbls (or 9%) and natural gas volumes declined by 353 MMcf (or 19%) in 2016 compared to 2015.  The lower oil volumes between periods was primarily related to normal field production decline and three wells that were shut-in in late 2015.The gas volume decrease was primarily related to (i) normal field production decline, (ii) eight gas wells that were shut-in during 2016 and in latter 2015, (iii) gas being flared instead of produced from six wells in the Keystone South field due to a gas plant in Texas being shutdown for a portion of 2016 and (iv) differences in timing associated with revenues received from non-operated properties.  These lower oil and gas volumes were partially offset by four workover wells and one recompleted well, all of which came back online during2016 and in latter 2015.Based on the December 31, 2016 reserve report, overall production attributable to the underlying properties is expected to decline at an average year-over-year rate of approximately 12.1%for oil and 15.4% for gas from 2017 through the estimated July 31, 2023 NPI termination date.

Lease Operating Expenses. LOE decreased  $10.8million (or 26%) during the year ended December 31, 2016 compared to the same 2015 periodprimarily due to (i) a  $6.9 million decrease in oilfield goods and services, (ii) a $2.4 million decline in ad valorem taxes and (iii) lower labor and other operating costs on Whiting-operated properties of $1.5 million.LOE on a per BOE basis declined 17%  from $29.14 during 2015 to$24.26 for 2016. This lower LOE rate was mainly due to the decrease in ad valorem taxes and cost reduction measures implemented by Whiting and other operators, and the general downturn in the oil and gas industry which has resulted in declining costs for oilfield goods and services.

Production Taxes. Production taxes are typically calculated as a percentage of oil and gas revenues, and production taxes as a percent of revenues remained consistent at 5.1%during 2016 and 2015. Overall production taxes in 2016, however, decreased $1.2 million (or 37%) as compared to 2015 primarily due to lower oil and natural gas sales revenue.

Development Costs. Development costs were $2.5 million (or 44%) lowerin 2016as compared to 2015.  This decrease was primarily related to reduced drilling and workover costs of $2.9 million between periods in the Rangely, Garland, Cedar Hills, Deb, Sable, Martin, Lake Como, Keystone South and North Vacuum fields.These lower expenditures were partially offset by well equipment improvements of $0.6 million incurred during 2016 in the Torchlight field

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 oil price volatility. If current market prices were lower than a collar’s price floor when the cash settlement amount was calculated, Whiting received cash proceeds from the contract counterparty. Conversely, if current market prices were higher than a collar’s price ceiling when the cash settlement amount was calculated, Whiting was required to pay the contract counterparty.

There were no cash settlements for these hedges during the year ended December 31, 2016. Cash settlements relating to these hedges, however, resulted in a gain of $1.0 million for the year ended December 31, 2015, which had the effect of increasing the average price of crude oil by $0.88 per Bbl for the year. As a result, the total net crude oil price of $49.79 per Bbl included a premium of 2% related to the effects of hedging for 2015. All hedge-related pricing impacts ceased after the February 2015 distribution, while the Trust’s net profits interest is currently projected to terminate on July 31, 2023 based on the Trust’s December 31, 2016 reserve report. Therefore, there areno further cash settlements on commodity hedges for inclusion in the Trust’s computation of net proceeds, which has the effect of increasing the Trust’s exposure to oil and natural gas price volatility.

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Proceeds from Sale of Oil and Gas Properties. During November 2015, Whiting completed the sale of certain producing oil and gas wells (effective for sales proceeds and costs beginning September 1, 2015) for a purchase price of $0.4 million ($0.3 million to the 90% net profits interest). The divested properties included nine wells located within Cooks Peak field in North Dakota, which had proved reserves of 18.14 MBOE (16.32 MBOE to the 90% net profits interest).Additionally, in September 2016, Whiting completed the sale of three shut-in oil and gas wells (effective for all cost and sales proceeds, if any, beginning September 1, 2016) for a total purchase price of $65,000 ($58,500 to the 90% net profits interest). The divested properties were located within the Chester and Blair fields in Michigan and had no remaining proved reserves since these wells were being prepared for plugging and abandonment operations by Whiting. The sales proceeds attributable to the NPI were included in the calculation of net cash proceeds available for distribution during the first quarter of 2016 and fourth quarter of 2016, respectively. There were no such sales during the year ended December 31, 2015.

Comparison of Results of the Trust for the Years Ended December 31, 2015 and 2014

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 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, development costs and cash settlements on commodity derivatives as follows:

Revenues. Oil and natural gas revenues were $56.5 million (or 48%) lower in 2015 compared to 2014. Sales revenue is a function of average commodity prices realized and oil and gas volumes sold. The decline in revenue between periods was due to significantly lower realized oil and natural gas prices, as well as lower oil and natural gas production volumes. The average sales price realized decreased for crude oil (before the effects of hedging) and natural gas by 44% and 42%, respectively, between periods due to lower NYMEX oil and natural gas prices. The Trust’s natural gas wells experienced a higher rate of production decline as compared to the Trust’s oil properties. Crude oil production volumes declined by 87 MBbls (or 7%) and natural gas volumes declined by 372 MMcf (or 17%) in 2015 compared to 2014. The oil volume decrease was primarily related to (i) normal field production decline, (ii) differences in timing associated with revenues received from non-operated properties and (iii) three wells that were shut-in at the end of 2014. These oil volume declines were partially offset by two wells that were shut-in for a portion of the 2014 period that came back online during February 2014 and one recompleted well that came online during the last twelve months. The gas volume decrease was primarily related to normal field production decline and two wells that were shut-in at the end of 2014. These lower gas volumes were partially offset by (i) one well recompletion performed in 2015, (ii) differences in timing associated with revenues received from non-operated properties and (iii) one well that was shut-in for a portion of the 2014 period.

Lease Operating Expenses. LOE decreased $2.3 million (or 5%) during the year ended December 31, 2015 compared to the same 2014 period primarily due to a $3.3 million decrease in oil field goods and services and lower labor and other operating costs on Whiting-operated properties of $1.6 million. These declines were partially offset by $2.6 million in higher ad valorem taxes paid during 2015, which tax bills were primarily assessed using 2014 commodity prices. LOE on a per BOE basis, however, increased 5%  from $27.86 during 2014 to $29.14 for 2015. This higher LOE rate was mainly due to overall production declining at a faster rate than the fixed and semi-variable costs attributable to the underlying properties.

Production Taxes. Production taxes are typically calculated as a percentage of oil and gas revenues, and production taxes as a percent of revenues remained relatively consistent at 5.1% and 5.2% during 2015 and 2014, respectively. Overall production taxes in 2015, however, decreased $3.0 million (or 50%) as compared to 2014, which decline is primarily due to lower oil and natural gas sales revenue between periods.

Development Costs. Development costs were $3.3 million (or 36%) lower in 2015 as compared to 2014. This decrease was primarily related to (i) fewer well workovers and recompletions in the DEB, Keystone South and Agua Dolce fields between periods, which totaled $2.3 million and (ii) reduced drilling and workover costs of $1.0 million in the Sable and Garland fields.  

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 oil price volatility. If market prices were lower than a collar’s price floor when the cash settlement amount was calculated, Whiting received cash proceeds from the contract counterparty. Conversely, if market prices were higher than a collar’s price ceiling when the cash settlement amount was calculated, Whiting was required to pay the contract counterparty.

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Cash settlements relating to these hedges resulted in a gain of $1.0 million for the year ended December 31, 2015, which had the effect of increasing the average price of crude oil by $0.88 per Bbl for the year. As a result, the total net crude oil price of $49.79 per Bbl included a premium of 2% related to the effects of hedging for 2015. There were no cash settlements for these hedges during the year ended December 31, 2014. All hedge-related pricing impacts ceased after the February 2015 distribution.Therefore, there are no further cash settlements on commodity hedges for inclusion in the Trust’s computation of net proceeds, which has the effect of increasing the Trust’s exposure to oil and natural gas price volatility.

Liquidity and Capital Resources

Overview. 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 paid 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 (i) any cash the Trustee decides to hold as a reserve against future liabilities and (ii) any accumulated net losses to be recovered by Whiting, plus accrued interest. If the NPI continues to generate net losses or limited net proceeds, as was the case for all four calendar quarters of 2016 as well as the February 2017 distribution, the net profits interest may not provide sufficient funds to the Trustee to enable it to pay all of the Trust’s administrative expenses. The Trust may borrow the amount of funds required to pay its liabilities if the Trustee determines that the cash on hand and the cash to be received, which is dependent on future net proceeds, are insufficient to cover the Trust’s liabilities. If the Trust borrows funds, the Trust unitholders will not receive distributions until the borrowed funds together with any accumulated net losses and accrued interest are repaid. As of February 28, 2017, the Trust had cash reserves of $0.3 million for the payment of its administrative expenses.

If the Trustee determines that the Trust’s cash reserves are insufficient to cover the general and administrative expenses of the Trust during periods when the NPI generates net losses or minimal net proceeds, Whiting intends to loan to the Trust the amount of funds necessary to satisfy payment of its liabilities. Additionally, 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.

Letter of Credit. In June 2012, Whiting established a $1.0 million letter of credit for the Trust 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 if the Trustee were to draw on the letter of credit or were to borrow funds from Whiting or other entities, no further distributions would be made to unitholders until all such amounts have been repaid by the Trust.

Reserve for Expenditures. Whiting may reserve from the gross proceeds amounts up to a total of $2.0 million at any time for future development, maintenance or operating expenses. However, Whiting has not funded such a reserve since the inception of the Trust, including during the years ended December 31, 2016, 2015 and 2014. Instead, Whiting has deducted from the Trust’s gross proceeds only actual costs paid for development, maintenance and operating expenses.

Plugging and Abandonment. Plugging and abandonment costs related to the underlying properties, net of any proceeds received from the salvage of equipment, cannot be included as a deduction in the calculation of net proceeds pursuant to the terms of the conveyance agreement. During the year ended December 31, 2016, Whiting incurred $0.6 million of plugging and abandonment charges on the underlying properties, and these costs were not charged to the unitholders of the Trust.

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.

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Contractual Obligations

The following table summarizes the Trust’s obligations and commitments as of December 31, 2016 to make future payments during the specified time periods (in thousands):

	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years(4)
Delaware Trustee fees(1)	$	25	$	4	$	7	$	7	$	7
Trustee administrative service fees(2)		1,301		179		372		391		359
Whiting administrative service fees(3)		1,317		200		400		400		317
Total	$	2,643	$	383	$	779	$	798	$	683

____________

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

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

(3) 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.

(4) The “more than 5 years” period represents obligations through the July 2023 estimated Trust termination date, based on the Trust’s 2016 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, 2016 applicable to the Trust or its financial statements.

Critical Accounting Policies and Estimates

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

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

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

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

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

d. Cash reserves for Trust expenses may be established by the Trustee for certainexpenditures that would not be recorded as contingent liabilitiesunder 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 and impairment charges to date.

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

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and production costs, may justify revision of such estimates. Accordingly, oil and gas quantities ultimately recovered and the timing of production may be substantially different from estimates, and the Trust is unable to predict changes in reserve quantity estimates as such quantities are dependent on future economic and operational conditions.

The standardized measure of discounted future net cash flows is prepared using assumptions made pursuant toFASB 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 and development expenditures. Discounted future net cash flows are calculated using a 10% discount rate. Changes in any of these assumptionscould 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. The investment in net profits interest is amortized using the units-of-production method. The 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 amortization expense is recordedwould increase, reducing Trust corpus.

Impairment of Investment in Net Profits Interest. The value of the investment in net profits interest is reviewed 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 isdetermined 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 and source of income to the Trust is the term NPI, which generally entitles the Trust to receive 90% of the net proceeds from oil and gas production from the underlying properties. Consequently, the Trust is exposed to market risk from fluctuations in oil and gas prices. Through 2014, however, the NPI was subject to commodity hedge contracts in the form of costless collars entered into by Whiting, which hadreducedthe NPI’s exposure to crude oil price volatility.

The revenues derived from the underlying properties depend substantially on prevailing crude oil, natural gas and natural gas liquids prices. As a result, commodity prices also affect the amount of cash flow available for distribution to the Trust unitholders. Lower prices may also reduce the amount of oil, natural gas and natural gas liquids that Whiting can economically produce. Whiting sells the oil, natural gas and natural gas liquid production from the underlying properties under floating market price contracts each month. Whiting entered into certain hedge contracts through December 31, 2014to manage the exposure to crude oil price volatility 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 2014.  However, all hedging contracts terminated as of December 31, 2014, which hedging effects extended through the quarterly payment period covered by the February 2015 distribution to unitholders.No additional hedges are allowed to be placed on Trust assets, and, therefore, there are no further cash settlements on commodity hedges for inclusion in the Trust’s computation of net proceeds (or net losses, as the case may be), which has the effect of increasing the Trust’s exposure to oil and natural gas price volatility. The Trust cannot enter into derivative contracts for speculative or trading purposes.

Crude oil costless collar arrangements settle based on the average of the closing settlement price for each commodity business day in the contract period. In Whiting’s collar arrangements, the counterparty was required to make a payment to Whiting for the difference between the fixed floor price and the settlement price if the settlement price was below the fixed floor price. Whiting was 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 was above the fixed ceiling price. The amounts that were received by Whiting from the counterparty upon settlements of these hedge contracts, if any, reduced the production and development costs related to the underlying properties when calculating net proceeds.

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Item 8. Financial Statements and Supplementary Data

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

INDEX TO MODIFIED CASH BASIS FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	51
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2016 and 2015	52
Statements of Distributable Income for the Years Ended December 31, 2016, 2015 and 2014	52
Statements of Changes in Trust Corpus for the Years Ended December 31, 2016, 2015 and 2014	52
Notes to Modified Cash Basis Financial Statements	53

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Trustee and Unit Holders of

Whiting USA Trust II

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

Austin, Texas

We have audited the accompanying statements of assets, liabilities and trust corpus of Whiting USA Trust II (the “Trust”) as of December 31, 2016 and 2015, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

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

As described in Note 2 to the financial statements these statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

In our opinion, such financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of Whiting USA Trust II as of December 31, 2016 and 2015, and its distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2016, on the comprehensive basis of accounting described in Note 2 to the financial statements.

/s/ Deloitte & Touche LLP

Austin, Texas

March 10, 2017

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WHITING USA TRUST II

Statements of Assets, Liabilities and Trust Corpus

(In thousands, except unit data)

	December 31,
	2016		2015
ASSETS
Cash and short-term investments	$	184	$	279
Investment in net profits interest, net		23,929		30,966
Total assets	$	24,113	$	31,245
LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses	$	184	$	279
Trust corpus (18,400,000 Trust units issued and outstanding    at December 31, 2016 and December 31, 2015)		23,929		30,966
Total liabilities and Trust corpus	$	24,113	$	31,245

Statements of Distributable Income

(In thousands, except distributable income per unit data)

	Year Ended December 31,
	2016		2015		2014
Income from net profits interest	$	1,548	$	10,161	$	52,362
General and administrative expenses		(823)		(801)		(881)
Proceeds from sale of oil and gas properties		389		-		-
Cash reserves used (withheld) for current Trust expenses		95		11		(69)
State income tax withholding		(10)		(11)		(23)
Distributable income	$	1,199	$	9,360	$	51,389
Distributable income per unit	$	0.065170	$	0.508693	$	2.792906

Statements of Changes in Trust Corpus

(In thousands)

	Year Ended December 31,
	2016		2015		2014
Trust corpus, beginning of period	$	30,966	$	57,789	$	144,990
Distributable income		1,199		9,360		51,389
Distributions to unitholders		(1,199)		(9,360)		(51,389)
Impairment of investment in net profits interest		-		(15,808)		(62,806)
Amortization of investment in net profits interest		(7,037)		(11,015)		(24,395)
Trust corpus, end of period	$	23,929	$	30,966	$	57,789

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

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WHITING USA TRUST II

NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS

1.  ORGANIZATION OF THE TRUST

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

The Trust was created to acquire and hold a term net profits interest (“NPI”) for the benefit of the Trust unitholders pursuant to a conveyance from Whiting Oil and Gas, a 100%-owned subsidiary of Whiting, to the Trust. The term NPI is an interest in certain of Whiting Oil and Gas’ properties located in the Permian Basin, Rocky Mountains, Gulf Coast and Mid-Continent regions (the “underlying properties”). The NPI is the only asset of the Trust, other than cash reserves held for future Trust expenses. As of December 31, 2016, these oil and gas properties included interests in approximately 1,314gross (379.4net) 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 Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), or (b) the sale of the net profits interest. The Trust will soon thereafter wind up its affairs and terminate, after which it will pay no further distributions. The Trust is required to sell the NPI and liquidate if cash proceeds to the Trust from the net profits interest are less than $2.0 million for each of any two consecutive years. During the year ended December 31, 2016, the Trust received cash proceeds of $1.9 million from the net profits interest.

As of December 31, 2016, on a cumulative accrual basis 6.89 MMBOE (65%) of the 10.61 MMBOE attributable to the NPI have been produced and sold or divested. The portion of Trust reserves divested through December 31, 2016 includes 0.02 MMBOE of proved reserves from certain producing oil and gas wells located within the Cooks Peak field in North Dakota that were sold for a purchase price of $0.4 million ($0.3 million to the 90% net profits interest) during the first quarter of 2016. Additionally, Whiting divested three shut-in oil and gas wells located within the Chester and Blair fields in Michigan for a purchase price of $65,000 ($58,500 to the 90% net profits interest) during the fourth quarter of 2016. However, these divested properties had no remaining proved reserves since these wells were being prepared for plugging and abandonment operations by Whiting. The remaining minimum reserve balance of 3.72 MMBOE (at the 90% NPI) is projected to be produced by July 31, 2023, based on the Trust’s year-end 2016 reserve report.

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

Delisting of the Trust—The Trust was informed by the New York Stock Exchange (the “NYSE”) on January 4, 2016 that the Trust was not in compliance with the NYSE’s continued listing standards, which require that the average closing price of the Trust units cannot be less than $1.00 per unit over a period of 30 consecutive trading days. Under the NYSE delisting procedures, the Trust had the right to certain cure periods if it could demonstrate its intent to cure the deficiency. However, in order to save the Trust administrative costs (including ongoing NYSE listing fees, expenses associated with reverse split votes or other actions necessary to remedy the deficiency) the Trust determined it would not cure the deficiency. As a result, the Trust units ceased trading on the NYSE on January 6, 2016. The Trust units transitioned to OTC, operated by OTC Markets Group, effective with the opening of trading on January 7, 2016 under the trading symbol “WHZT.”

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Term Net Profits Interest—  The Trust uses the modified cash basis of accounting to report Trust receipts from the term NPI and payments of expenses incurred. Actual cash distributions to the Trust are made based on the terms of the conveyance that created the

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Trust’s NPI. The term NPI entitles the Trust to receive revenues (oil, gas and natural gas liquid sales) less expenses (the amount by which all royalties; lease operating expenses including well workover costs; development costs; production and property taxes; payments made by Whiting to the hedge counterparty upon settlements of hedge contracts; maintenance expenses; producing overhead; and amounts that may be reserved for future development, maintenance or operating expenses, which reserve amounts may not exceed $2.0 million; exceed hedge payments received by Whiting under hedge contracts and other non-production revenue) of the underlying properties multiplied by 90% (term NPI percentage). Actual cash receipts may vary due to timing delays of cash receipts from the property operators or purchasers and due to wellhead and pipeline volume balancing agreements or practices, subject to adjustment for the recovery of accumulated net losses funded by Whiting and accrued interest.

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

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

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

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

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

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

f. The Trust evaluates impairment of the investment in net profits interest by comparing the undiscounted cash flows expected to be realized from the investment in net profits interest to the NPI carrying value. If the expected future undiscounted cash flows are less than the carrying value, the Trust recognizes an impairment loss for the difference between the carrying value and the estimated fair value of the investment in net profits interest. The fair value of the NPI is determined using the expected net discounted future cash flows from the underlying properties that are attributable to the net profits interest. The determination of whether the NPI is impaired requires a significant amount of judgment by the Trustee and is based on the best information available to the Trustee at the time of the evaluation.

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 ofRoyalty Trusts.

Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with GAAP, directing such entities to accrue or defer certain revenues and expenses in a period other than when such revenues are received or expenses are paid. Because the Trust’s financial statementsare 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 Investments— Cash and short-term investments include all highly liquid short-term investments with original maturities of three months or less.

Concentration of Credit Risk — The underlying properties from which the NPI is derived principally sell their oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. The following table presents the percentages by purchaser that accounted for 10% or more of the underlying properties’total oil and gas sales for the years ended December 31, 2016,2015 and 2014.

	2016	2015	2014
Plains Marketing, LP	16%	15%	15%
Chevron USA	15%	15%	15%
Phillips 66 Company	11%	11%	11%
Marathon Oil Corporation	9%	14%	11%

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

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

Recent Accounting Pronouncements—There were no accounting pronouncements issued during the year ended December 31, 2016 applicable to the Trust or its financial statements.

3.  INVESTMENT IN NET PROFITS INTEREST

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

Oil and gas properties	$	368,786
Accumulated depletion		(174,626)
Oil and gas properties, net		194,160
Derivative liability		(128)
Net predecessor cost of net profits interest conveyed to the Trust	$	194,032

Accumulated amortization of the investment in net profits interestwas $7.0 million as of December 31, 2016and zero as of December 31, 2015, which was the result of an NPI impairment write down that occurred at year-end 2015.

Impairment of Net Profits Interest— The investment in net profits interest is evaluated for impairment when events and circumstances indicate that the recorded carrying value may not be recoverable. Any impairment of the investment in net profits interest is charged directly to Trust corpus, which does not affect distributable income. During 2016, no impairment of the investment in net profits interest occurred. During 2015, the investment in net profits interest with a previous carrying value of $46.8 million was written down to its fair value of $31.0 million, resulting in an impairment of $15.8 million. This write-down of the investment in NPI was related to decreases in the forward price curves for crude oil and natural gas as of December 31, 2015. The fair value of the investment in net profits interest contains unobservable inputs including estimates of future oil and gas production attributable to the Trust; commodity prices based on sales contract terms or forward price curves (adjusted for basis differentials); estimated operating, development, and general and administrative expenses; estimated state income tax withholdings; and a risk-adjusted discount rate.

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4.  INCOME FROM NET PROFITS INTEREST

The Trust received income from net profits interest as follows:

	Year Ended December 31,
	2016			2015			2014
Revenues:
Oil sales(1)	$	34,706	(3)	$	55,006	(4)	$	105,189	(5)
Natural gas sales		3,278	(3)		6,005	(4)		12,307	(5)
Total revenues		37,984			61,011			117,496
Costs:
Lease operating expenses		31,101			41,873			44,192
Production taxes		1,941			3,091			6,124
Development costs		3,222			5,746			8,999
Cash settlements on commodity derivatives(2)		-			(989)			-
Total costs		36,264			49,721			59,315
Net proceeds		1,720			11,290			58,181
Net profits percentage		90	%		90	%		90	%
Income from net profits interest	$	1,548		$	10,161		$	52,362

____________

(1) Oil includes natural gas liquids.

(2) As discussed in “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of this Annual Report on Form 10-K,all costless collar hedge contracts terminated as of December 31, 2014 (which hedging effects extended through the quarterly payment period covered by the February 2015 distribution to unitholders), and no additional hedges are allowed to be placed on Trust assets. Consequently, there are no further cash settlements on commodity hedges, and the Trust will have increased exposure to oil and natural gas price volatility.

(3) Oil and gas sales volumes and related revenues for the year ended December 31, 2016 (consisting of the February 2016 and May 2016 net losses and August 2016 and November 2016 distributions) generally represent crude oil production from October 2015 through September 2016 and natural gas production from September 2015 through August 2016.

(4) Oil and gas sales volumes and related revenues for the year ended December 31, 2015 (consisting of Whiting’s February 2015, May 2015, August 2015 and November 2015 distributions to the Trust) generally represent crude oil production from October 2014 through September 2015 and natural gas production from September 2014 through August 2015.

(5) Oil and gas sales volumes and related revenues for the year ended December 31, 2014 (consisting of Whiting’s February 2014,  May 2014, August 2014 and November 2014 distributions to the Trust) generally represent crude oil production from October 2013 through September 2014 and natural gas production from September2013 through August 2014.

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$10,169,$11,183and $23,009related to Montana state income taxes for the years ended December 31, 2016,2015 and 2014, respectively. For Arkansas, Colorado, Michigan, Mississippi, New Mexico, North Dakota and Oklahoma, neither the Trust nor Whiting is withholding the income tax due such states on distributions made to an 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 to any cash reserves established for future expenses of the Trust or adjustments for the recovery of accumulated net losses and accrued interest.

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There were no distributions to the Trust unitholders during the first three calendar quarters of 2016 primarily due to the net profits interest generating net losses or limited net proceeds as a result of lower oil and natural gas prices during those quarterly payment periods. The NPI generated net losses of $1.2 million during the second quarter of 2016 which net losses were funded by Whiting at the time they were incurred. All accumulated net losses, plus accrued interest, were recovered by Whiting in full during the third calendar quarter of 2016. There were no accumulated net losses funded or recovered by Whiting during the years ended December 31, 2015 and 2014.

Neither the Trust nor the unitholders are liable for any net losses that are generated by the net profits interest; however, any such net losses, plus accrued interest at the prevailing money market rate, are to be recovered by Whiting from future NPI gross proceeds before any further distributions will be made to Trust unitholders, as occurred during the third quarter of 2016. Additionally, if the Trust borrows funds in order to pay its administrative liabilities, the Trust unitholders will not receive distributions until the borrowed funds together with any accumulated net losses and accrued interest are repaid.

The following table presents the net profits interest accumulated net losses for the years ended December 31, 2016, 2015 and 2014 (in thousands):

	Year Ended December 31,
	2016		2015		2014
Accumulated net losses, beginning of period	$	-	$	-	$	-
Net losses funded by Whiting		(1,201)		-		-
Accumulated net losses recovered by Whiting(1)		1,201		-		-
Accumulated net losses, end of period	$	-	$	-	$	-

____________

(1) In addition to the repayment of the accumulated net losses of $1.2 million, accrued interest of $657 was also recovered by Whiting during the third quarter of 2016, which amount is included in general and administrative expenses in the 2016 statement of distributable income.

7.  RELATED PARTY TRANSACTIONS

Plugging and Abandonment — During the years ended December 31, 2016,  2015 and 2014, Whiting incurred $0.6 million,  $0.1 million and $1.5 million, respectively, of plugging and abandonment costs on the underlying properties. Pursuant to the terms of the conveyance agreement, plugging and abandonment charges relating to the underlying properties, net of any proceeds received from the salvage of equipment, are funded entirely by Whiting and are not therefore included as a deduction in the calculation of net proceeds or otherwise deducted from Trust unitholders over the term of the Trust.

Operating Overhead — Pursuant to the terms of itsjoint operating agreements, Whiting deducts from the gross oil and gas sales proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally, with respect to those underlying properties for which Whiting is the operator but where there is no operating agreement in place, Whiting deducts from the gross proceeds an overhead fee calculated in the same manner that Whiting allocates overhead to other similarly owned properties, which is customary practice in the oil and gas industry.  Operating overhead activities include various engineering, legal, and administrative functions. The fee is adjusted annually pursuant to COPAS guidelines and will increase or decrease each year based on changes in the year-end index of average weekly earnings of crude petroleum and natural gas workers. The following table presents the Trust’s portion of these overhead chargesfor the distributions made during the years ended December 31, 2016,2015 and 2014 (dollars in thousands, except monthly amounts per well):

	Year Ended December 31,
	2016		2015		2014
Total overhead charges (in thousands)	$	1,561	$	1,694	$	1,746
Overhead charge per month per active operated well	$	409	$	437	$	446

Administrative Services Fee — Under the terms of the administrative services agreement, the Trust is obligated to pay a quarterly administration fee of $50,000 to Whiting 60 days following the end of each calendar quarter. General and administrative expenses in the Trust’s statements of distributable income for the yearsendedDecember 31, 2016,2015 and 2014includes$200,000in each period for quarterly administrative fees paid to Whiting.

Trustee Administrative Fee — Under the terms of the Trust agreement, the Trust pays an annual administrative fee to the Trustee of $175,000, which is paid in four quarterly installments of $43,750 each and is billed in arrears. Starting in 2017, such fee escalates by 2.5% each year. General and administrative expenses in the Trust’s statements of distributable income for the years endedDecember 31, 2016,2015 and 2014includes$175,000in each period for administrative fees paid to the Trustee.

57

Letter of Credit — InJune 2012, Whiting established a $1.0 million letter of credit for the Trustee in order to provide it with a mechanism to pay the operating expenses of the Trust, in the event that Whiting should fail to lend fundsto the Trust,if requested to do so by the Trustee.This letter of credit will not be used to fund NPI distributions to unitholders, andif  the Trustee were to draw on the letter of credit or were to borrow funds from Whiting or other entities, no further distributions would be made to unitholders until all such amounts, including interest thereon if applicable, have been repaid by the Trust.

Lending to the Trust —The Trustee can authorize the Trust to borrow money for the purpose of paying Trust administrative or incidental expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee, Whiting or the Delaware Trustee as a lender, provided that the terms of the loan are similar to the terms it would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself, which may be a non-interest bearing account, and make other short term investments with the funds distributed to the Trust. As of December 31, 2016 and 2015, the Trust had no borrowings outstanding.

8.  SUBSEQUENT EVENTS

On March 1, 2017, a distribution of $0.063784 per Trust unit was paid to Trust unitholders of record on February 19, 2017 (which resulted in an effective record date of February 17, 2017). This aggregate distribution to all Trust unitholders consisted of net cash proceeds of $1.5 million paid by Whiting to the Trust, less a provision of $0.3 million for estimated Trust expenses and $2,358 for Montana state income tax withholdings.  

58

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS RESERVE INFORMATION (UNAUDITED)

Oil and Gas Reserve Quantities

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 and cost changes and other factors.

As of December 31, 2016, 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 maintained.

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, 2014,  2015 and 2016:

	Oil (MBbl)	Natural Gas (MMcf)	Total (MBOE)
Balance — January 1, 2014(1)	6,491	9,950	8,149
Revisions to previous estimates	(40)	(561)	(133)
Extensions and discoveries	7	1	7
Divestitures	-	-	-
Production	(1,106)	(1,927)	(1,427)
Balance — December 31, 2014(1)(2)	5,352	7,463	6,596
Revisions to previous estimates	(270)	(1,333)	(493)
Extensions and discoveries	8	-	8
Divestitures	(15)	(10)	(16)
Production	(1,002)	(1,615)	(1,271)
Balance — December 31, 2015(1)(2)	4,073	4,505	4,824
Revisions to previous estimates	82	(484)	2
Extensions and discoveries	4	-	4
Divestitures	-	-	-
Production	(902)	(1,257)	(1,112)
Balance — December 31, 2016(1)(2)	3,257	2,764	3,718
Proved developed reserves:
December 31, 2013	6,475	9,950	8,133
December 31, 2014	5,337	7,463	6,581
December 31, 2015	4,073	4,505	4,824
December 31, 2016	3,257	2,764	3,718
Proved undeveloped reserves:
December 31, 2013	16	-	16
December 31, 2014	15	-	15
December 31, 2015	-	-	-
December 31, 2016	-	-	-

____________

(1) Reserves related to the underlying properties on a 100% full economic life basis as of January 1, 2014, December 31, 2014,  2015 and 2016 were 14.8 MMBOE,13.4MMBOE,8.9MMBOE and 7.4 MMBOE, respectively. The oil and gas reserve quantities presented in the tables above are on a 90% NPITrust life basis.

(2) The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021 or (2) the time when the Trust’s minimum volumes of 10.61 MMBOE have been produced and sold from the underlying properties, or (b) the sale of the net profits interest. The reserve report as of December 31, 2014had the underlying properties projected to produce the Trust’s minimum volumes prior to December 31, 2021.Since the net profits interest was not expected to contractually terminate until December 31, 2021, the December 31, 2014 reserve report included 592 MBOEof additional reserves attributable to the 90% NPI in excess of the Trust’s minimum volumes. The December 31, 2015and 2016 reserve reports, however, 59  

project that the underlying properties would produce the Trust’s minimum volumesby June 30, 2022 and July 31, 2023, respectively, whereby the Trust would only be entitled to receive the minimum volumes of 10.61 MMBOE.

Notable changes in proved reserves for the year ended December 31, 2016 included:

· Revisions to previous estimates.In 2016, revisions to previous estimates increased proved reserves by a net amount of 2 MBOE. Included in these revisions were (i) 472 MBOE of net upward adjustments attributable to reservoir analysis and enhanced well performance and (ii) 470 MBOE of downward adjustments caused by lower oil and gas pricing incorporated into the Trust’s reserve estimates at December 31, 2016 as compared to December 31, 2015.

Notable changes in proved reserves for the year ended December 31, 2015 included:

· Revisions to previous estimates.In 2015,  revisions to previous estimates decreased proved reserves by a net amount of 493 MBOE. These revisions include a downward adjustment of 592 MBOE as a result of the December 31, 2015 reserve report projecting the net profits interest to terminate by June 30, 2022 as compared to the December 31, 2014 reserve report’s projected termination date of December 31, 2021. The extension of the expected termination date of the NPI was caused by lower oil and gas pricing incorporated into the Trust’s reserve estimates at December 31, 2015 as compared to December 31, 2014. This downward revision was partially offset, however, by an increase of 99 MBOE attributable to well performance.

Notable changes in proved reserves for the year ended December 31, 2014 included:

· Revisions to previous estimates.  In 2014, revisions to previous estimates decreased proved reserves by a net amount of 133 MBOE. These revisions mainly consisted of lower crude oil and natural gas pricing incorporated into the Company’s reserve estimates at December 31, 2014 as compared to December 31, 2013.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure relating to proved oil and gas reserves and the changes in the standardized measure relating to proved oil and natural gas reserves were prepared in accordance with the provisions of FASB ASC Topic 932,Extractive Activities—Oil and Gas.Future cash inflows as of each period end 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) to estimated future production.Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming the continuation of existing economic conditions. The standardized measure of discounted future net cash flows has not been reduced by federal or state income taxes due to taxable income being passed through to the unitholders of the Trust.

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

	December 31,
	2016		2015		2014
Future cash inflows	$	118,743	$	184,764	$	487,684
Future production costs		(80,734)		(117,049)		(243,640)
Future development costs		(11,085)		(15,414)		(24,753)
Future net cash flows		26,924		52,301		219,291
10% annual discount for estimated timing of cash flows		(5,945)		(11,266)		(51,092)
Standardized measure of discounted future net cash flows(1)	$	20,979	$	41,035	$	168,199

____________

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

60

The changes in the standardized measure relating to proved oil and gas reserves attributable to the Trust are as follows (in thousands):

	December 31,
	2016		2015		2014
Beginning of year	$	41,035	$	168,199	$	225,064
Sale of oil and gas produced, net of production costs		(4,517)		(9,542)		(51,942)
Sale of minerals in place		-		(481)		-
Net changes in prices and production costs		(23,820)		(127,291)		(26,582)
Extensions and discoveries less related costs		37		91		244
Previously estimated development costs incurred during the period		2,601		4,785		4,569
Changes in estimated future development costs		1,521		3,267		(1,028)
Revisions of previous quantity estimates		18		(14,813)		(4,632)
Accretion of discount		4,104		16,820		22,506
End of year	$	20,979	$	41,035	$	168,199

Future cash inflows included in the standardized measure relating to proved oil and natural gas reserves incorporate weighted average sales prices (inclusive of adjustments for quality and location)as follows:

	December 31,
	2016		2015		2014
Oil (per Bbl)	$	34.47	$	42.57	$	83.26
Gas (per Mcf)	$	2.34	$	2.53	$	5.64

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SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

		Three Months Ended(1)
	March 31		June 30		September 30		December 31		Total
Year Ended December 31, 2016
Income from net profits interest	$	(92)	$	(1,198)	$	1,445	$	1,393	$	1,548
Distributable income	$	-	$	-	$	-	$	1,199	$	1,199
Distributions per unit	$	-	$	-	$	-	$	0.065170	$	0.065170
Year Ended December 31, 2015
Income from net profits interest	$	6,177	$	536	$	3,172	$	276	$	10,161
Distributable income	$	6,022	$	236	$	2,919	$	183	$	9,360
Distributions per unit	$	0.327255	$	0.012803	$	0.158632	$	0.010003	$	0.508693

____________

(1) Dollars in thousands, except distributions per unit.

******

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Item 9. Changes in and Disagreements with Accountants on Accounting andFinancial 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 (the “Exchange Act”) 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 Trust’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 on oil and gas 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 operations.

Changes in Internal Control over Financial Reporting. During the quarter ended December 31, 2016,  there was no change in the Trust’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of Whiting.

Trustee’s Annual Report on Internal Control Over Financial Reporting.  A registrant's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the modified cash basis of accounting. 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 the modified cash basis of accounting, and that receipts and expenditures of the registrant are being made only in accordance with authorizations of the Trustee; 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 Exchange Act. 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.

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.

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  (2013) 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  (2013), the Trustee concluded that the Trust's internal control over financial reporting was effective as of December 31, 2016.

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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 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. Based solely on a review of these reports and any such reports furnished to the Trustee, the Trustee is not aware of any 10 percent unitholder having failed to comply with all Section 16(a) filing requirements in 2016.

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 of New York Mellon Trust Company’s code of ethics.

Item 11. Executive Compensation

During the year ended December 31, 2016,the Trustee received administrative fees from the Trust in the amount of $175,000. The Trust does not have any executive officers, directors or employees. Because the Trust does not have a board of directors, it does not have a compensation committee.

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

(a) Security Ownership of Certain Beneficial Owners.

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

(b) Security Ownership of Management.

Not applicable.

(c) Changes in Control.

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

64

Item 13. Certain Relationships,Related Transactions and Director Independence

Letter of Credit

In June 2012, Whiting established a $1.0 millionletter of credit forthe 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 fundsto the Trust,if requested to do so by the Trustee.This letter of credit will not be used to fund NPI distributions to unitholders, andif  the Trustee were to draw on the letter of credit or were to borrow funds from Whiting or other entities, no further distributions would be made to the unitholders until all such amounts including interest therein if applicable, have been repaid by the Trust.

Plugging and Abandonment

During the year ended December 31, 2016, Whiting incurred $0.6 million of plugging and abandonment costs on the underlying properties. Pursuant to the terms of the conveyance agreement, plugging and abandonment charges relating to the underlying properties, net of any proceeds received from the salvage of equipment, are funded entirely by Whiting and are not therefore included as a deduction in the calculation of net proceeds or otherwise deducted from Trust unitholders over the term of the Trust.

Operating Overhead

Pursuant to the terms of itsjoint operating agreements, Whiting deducts from the gross oil and gas sales proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally, with respect to those underlying properties for which Whiting is the operator but where there is no operating agreement in place, Whiting deducts from the gross proceeds an overhead fee calculated in the same manner that Whiting allocates overhead to other similarly owned properties,  which is customary practice in the oil and gas industry.  Operating overhead activities include various engineering, legal, and administrative functions. For the year ended December 31, 2016, the Trust’s portion of the monthly charge totaled $1.6 millionand averaged $409per 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 endedDecember 31, 2016 include $200,000 for quarterly administrative fees paid to Whiting.

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

Trustee Administration Fee

Under the terms of the Trust agreement, the Trust pays an annual administrative fee to the Trustee of $175,000, which is paid in four quarterly installments of $43,750 each and is billed in arrears. Starting in 2017, such fee escalates by 2.5% each year. General and administrative expenses in the Trust’s statements of distributable income for the year endedDecember 31, 2016 include $175,000 for quarterly administrative fees paid to the Trustee.

Director Independence

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

Item 14. Principal Accounting 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 ending December 31, 2017. During fiscal 2016, Deloitte served as the Trust’s independent registered public accounting firm.

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The following table presents the aggregate fees billed to the Trust for the fiscal years ended December 31, 2016 and 2015by Deloitte:

	2016		2015
Audit fees(1)	$	185,000	$	212,000
Audit-related fees		-		-
Tax fees		-		-
All other fees		-		-
Total fees	$	185,000	$	212,000

____________

(1) Fees for audit services in 2016 and 2015consisted of the audit of the Trust’s annual financial statements and reviews of the Trust’s quarterly financial statements.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)(1) Financial Statements

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

(a)(2) Schedules

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

(a)(3) Exhibits

See Exhibit Index.

Item 16.Form 10-K Summary

None.

66

SIGNATURES

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

	Whiting USA Trust II
By:	The Bank of New York Mellon Trust Company, N.A.,
	as Trustee
By:	/s/ Mike Ulrich
	Mike Ulrich
	Vice President

March 10, 2017

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

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
	www.cgaus.com

February 9, 2017

The Bank of New York Mellon Trust Company, N.A.

 As Trustee of Whiting USA Trust II

919 Congress Avenue, Suite 500

Austin, Texas 78701

Re:	Evaluation Summary – SEC Price
	Whiting USA Trust II Underlying Properties
	Total Proved Reserves
	Certain Properties Located in Various States
	As of December 31, 2016
	Pursuant to the Guidelines of the Securities and
	Exchange Commission for Reporting Corporate
	Reserves and Future Net Revenue

Gentlemen:

We are submitting our estimates of total proved reserves and forecasts of economics attributable to the underlying properties, from which a net profits interest has been formed and conveyed by Whiting Petroleum Corporation to the Whiting USA Trust II.  These oil and gas properties are located in Texas, Wyoming, North Dakota, Colorado, New Mexico, Mississippi, Arkansas, Montana, Michigan and Oklahoma, and this report has been prepared for the Trustee of Whiting USA Trust II based on its request.  Included in the tables below are the total proved reserves attributable to (i) the same underlying properties through their full economic life and (ii) the same underlying properties but only the reserves estimated to be produced by July 31, 2023, which is the estimated termination date for Whiting USA Trust II.  This report, completed February 9, 2017 was prepared for the purpose of public disclosure by Whiting in filings made with the U.S. Securities and Exchange Commission (“SEC”) in accordance with the disclosure requirements set forth in SEC regulations, and it includes results for an SEC pricing scenario accordingly.  It covers 100% of the total proved reserves estimated for Whiting USA Trust II.  The results of this evaluation are presented in the two tables immediately below as follows:

Underlying Properties Full Economic Life
		Proved	Proved	Proved
		Developed	Developed	Developed	Total
Net Reserves		Producing	Shut-In	Behind Pipe	Proved
Oil	- Mbbl	5,946.8	0.0	316.1	6,262.9
Gas	- MMcf	4,195.3	0.0	607.6	4,802.9
NGL	- Mbbl	301.1	0.0	0.0	301.1
Equivalent*	- Mbbl	6,947.1	0.0	417.4	7,364.5
Revenue
Oil	- M$	207,285.0	0.0	12,071.9	219,356.8
Gas	- M$	9,560.0	0.0	1,819.5	11,379.6
NGL	- M$	6,094.2	0.0	0.0	6,094.2
Severance Taxes	- M$	9,146.2	0.0	691.8	9,838.0
Ad Valorem Taxes	- M$	9,152.3	0.0	244.1	9,396.4
Operating Expenses	- M$	141,026.8	0.0	4,908.6	145,935.4
Investments	- M$	14,560.6	0.0	2,006.6	16,567.2
Net Operating Income	- M$	49,053.2	0.0	6,040.4	55,093.6
Discounted @ 10%	- M$	30,133.8	0.0	2,074.8	32,208.6

Cawley, Gillespie & Associates, Inc.

Underlying Properties Reserves Estimated to be Produced by July 31, 2023
		Proved	Proved	Proved
		Developed	Developed	Developed	Total
Net Reserves		Producing	Shut-In	Behind Pipe	Proved
Oil	- Mbbl	3,373.0	0.0	48.6	3,421.6
Gas	- MMcf	3,071.5	0.0	0.0	3,071.5
NGL	- Mbbl	197.3	0.0	0.0	197.3
Equivalent*	- Mbbl	4,082.2	0.0	48.6	4,130.8
Revenue
Oil	- M$	118,753.2	0.0	1,871.5	120,624.7
Gas	- M$	7,180.9	0.0	0.0	7,180.9
NGL	- M$	4,131.0	0.0	0.0	4,131.0
Severance Taxes	- M$	6,134.8	0.0	86.1	6,220.9
Ad Valorem Taxes	- M$	5,090.7	0.0	43.2	5,133.9
Operating Expenses	- M$	77,536.5	0.0	812.8	78,349.3
Investments	- M$	11,716.2	0.0	600.0	12,316.2
Net Operating Income	- M$	29,586.8	0.0	329.4	29,916.3
Discounted @ 10%	- M$	23,166.8	0.0	143.5	23,310.2

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

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

Hydrocarbon Pricing

In accordance with SEC guidelines, hydrocarbon prices used in the preparation of this report have been determined as an unweighted arithmetic average of the first-day-of-the-month price for each month of 2016, unless prices were otherwise defined by contractual arrangements. Accordingly, NYMEX oil and Henry Hub Gas prices of $42.75 per bbl and $2.49 per MMBtu, respectively, were used as of December 31, 2016.  Further adjustments were applied on a lease level basis for oil price differentials, gas price differentials and heating values as furnished by your office. Prices were not escalated in the SEC scenario.  The average adjusted prices used in the estimation of proved reserves for the underlying properties full economic life were $35.03 per bbl of oil, $20.24 per bbl of natural gas liquids and $2.37 per mcf of natural gas.  For the proved reserves of the underlying properties estimated to be produced by July 31, 2023, the average adjusted prices were $35.25 per bbl of oil, $20.94 per bbl of natural gas liquids and $2.34 per mcf of natural gas.

Capital, Expenses and Taxes

Capital expenditures, lease operating expenses and ad valorem tax values were forecast as provided by your office.  As you explained, the capital costs were based on the most current estimates, lease operating expenses were based on the analysis of historical actual expenses, operating overhead is included for both operated and non-operated properties. Capital costs and lease operating expenses were held constant in accordance with SEC guidelines.  State severance tax rates were applied at current statutory percentages of oil and gas revenue, incorporating certain severance tax incentives and allowances for limited time periods where allowable in Whiting’s various tax jurisdictions.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 2 and 3 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.

Cawley, Gillespie & Associates, Inc.

Reserve Estimation Methods

The methods employed in estimating reserves are described on page 1 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.  All reserve estimates involve an assessment of the uncertainty relating to the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends mainly on the amount of the reliable geologic and engineering data available at the time of the estimate and the interpretation of such data, as well as the inherent uncertainties attributable to variations in reservoir and rock quality, offset drainage, mechanical wellbore integrity among others.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  This report addresses only the proved reserves attributable to the properties evaluated herein.

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

Miscellaneous

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

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

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

Yours very truly,

W. Todd Brooker, P. E.

Senior Vice President

Cawley, Gillespie & Associates

Texas Registered Engineering Firm F-693

Cawley, Gillespie & Associates, Inc.

APPENDIX

Methods Employed in the Estimation of Reserves

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

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

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

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

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

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

Analogy.  This method, which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. The analogy method may also be applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained in this manner 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 contain inherent uncertainties and 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.

Cawley, Gillespie & Associates, Inc.

APPENDIX

Reserve Definitions and Classifications

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

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

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

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

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

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

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

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

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

   “(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 Subpart 1200 of SEC Regulation S-K) or by other evidence using reliable technology establishing reasonable certainty.

Cawley, Gillespie & Associates, Inc.

"(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).”

Cawley, Gillespie & Associates, Inc.

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
	www.cgaus.com

Professional Qualifications of W. Todd Brooker,P.E.

Senior Vice President of Cawley, Gillespie & Associates

Mr. Brooker has been a Petroleum Consultant for Cawley, Gillespie & Associates (CG&A) since 1992, and became Senior Vice President in 2011.  His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures.  Prior to CG&A he worked in Gulf of Mexico drilling and production engineering at Chevron USA.  Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering.  He is a registered professional engineer in Texas, No. 83462, and a member of the Society of Petroleum Engineers (SPE).

EXHIBIT INDEX

Exhibit
Number	Description
3.1*	Certificate of Trust of Whiting USA Trust II [Incorporated herein by reference to Exhibit 3.3 to the Registration Statement on Form S-1 (Registration No. 333-178586)].
3.2*	Amended and Restated Trust Agreement, dated March 28, 2012, by and among Whiting Oil and Gas Corporation, The Bank of New York Mellon Trust Company, N.A. as Trustee and Wilmington Trust, National Association, as Delaware Trustee. [Incorporated herein by reference to Exhibit 3.1 to the Trust’s Current Report on Form 8-K filed on March 28, 2012 (File No. 001-35459)].
10.1*	Conveyance and Assignment, dated March 28, 2012, from Whiting Oil and Gas Corporation to The Bank of New York Mellon Trust Company, N.A. as Trustee of Whiting USA Trust II [Incorporated herein by reference to Exhibit 10.1 to the Trust’s Current Report on Form 8-K filed on March 28, 2012 (File No. 001-35459)].
10.2*	Administrative Services Agreement, dated March 28, 2012, by and between Whiting Oil and Gas Corporation and Whiting USA Trust II [Incorporated herein by reference to Exhibit 10.2 to the Trust’s Current Report on Form 8-K filed on March 28, 2012 (File No. 001-35459)].
31	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99	Report of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers dated February 9, 2017 [Incorporated by reference to Appendix 1 of this Annual Report on Form 10-K for the year ended December 31, 2016 filed on March 10, 2017 (File No. 001-35459)].

____________

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

EX-31

Exhibit 31

CERTIFICATION

I, Mike Ulrich, certify that:

1. I have reviewed this annual report on Form 10-K of Whiting USA Trust II, for which The Bank of New York Mellon Trust Company, N.A. acts as Trustee;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, distributable income and changes in Trust corpus of the registrant as of, and for, the periods presented in this report;

4. I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and I have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the basis of accounting described in Note 2;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected or is reasonably likely to materially affect the registrant's internal control over financial reporting; and

5. I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant's auditors:

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves any persons who have a significant role in the registrant's internal control over financial reporting.

In giving the foregoing certifications in paragraphs 4 and 5, I have relied to the extent I consider reasonable on information provided to me by Whiting Petroleum Corporation.

	Whiting USA Trust II
By:	The Bank of New York Mellon Trust Company, N.A.,
	as Trustee
By:	/s/ Mike Ulrich
	Mike Ulrich
	Vice President

Date: March 10, 2017

EX-32

Exhibit 32

Via EDGAR

Securities and Exchange Commission

100F Street, N.E.

Washington, D.C. 20549

Re: Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Ladies and Gentlemen:

In connection with the Annual Report of Whiting USA Trust II (the “Trust”) on Form 10-K for the year ended December 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, not in its individual capacity but solely as the trustee of the Trust, certifies pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to its knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.

The above certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350) and is not being filed as part of the Form 10-K or as a separate disclosure document.

	Whiting USA Trust II
By:	The Bank of New York Mellon Trust Company, N.A.,
	as Trustee
By:	/s/ Mike Ulrich
	Mike Ulrich
	Vice President

Date: March 10, 2017