Whiting USA Trust II (WHZT) 10-K 2019 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑K

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

For The Fiscal Year Ended December 31, 2019

OR

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

For the transition period from _______ to _______

Commission File Number 001‑35459

WHITING USA TRUST II

(Exact name of registrant as specified in its charter)

Delaware	38‑7012326
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
The Bank of New York Mellon Trust Company, N.A., Trustee
Global Corporate Trust
601 Travis Street, 16th Floor
Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(512) 236‑6599

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

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 every Interactive Data File required to be submitted 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 such files). Yes ☐   No   ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non‑accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b‑2 of the Exchange Act.

Large accelerated filer	☐	Smaller reporting company	☑
Accelerated filer	☐	Emerging growth company	☐
Non‑accelerated filer	☑

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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 28,  2019 of $1.18 was $21,712,000.

As of March 24, 2020,  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	18
Item 1B.	Unresolved Staff Comments	30
Item 2.	Properties	30
Item 3.	Legal Proceedings	37
Item 4.	Mine Safety Disclosures	37
PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	38
Item 6.	Selected Financial Data	39
Item 7.	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations	40
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	47
Item 8.	Financial Statements and Supplementary Data	48
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	59
Item 9A.	Controls and Procedures	59
Item 9B.	Other Information	59
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	60
Item 11.	Executive Compensation	60
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	60
Item 13.	Certain Relationships, Related Transactions and Director Independence	61
Item 14.	Principal Accounting Fees and Services	61
PART IV
Item 15.	Exhibits and Financial Statement Schedules	62
Item 16.	Form 10‑K Summary	62

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;

· the effect, impact, potential duration or other implications of the recent outbreak of a novel strain of coronavirus (“COVID-19”);

· 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, which include capital expenditures;

· 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 2017 distribution” The cash distribution to Trust unitholders of record on August 19, 2017 (which resulted in an effective record date of August 18, 2017 due to the 19th of August falling on a non‑trading day) that was paid on August 29, 2017.

“August 2018 distribution” The cash distribution to Trust unitholders of record on August 19, 2018 (which resulted in an effective record date of August 17, 2018 due to the 19th day of August falling on a non-trading day) that was paid on August 29, 2018.

“August 2019 distribution” The cash distribution to Trust unitholders of record on August 19, 2019 that was paid on August 29, 2019.

“average annual capital expenditure amount” The quotient of (a) the sum of (i) the capital expenditures and (ii) the amounts reserved for approved capital expenditure projects, in each case attributable to the three years ended December 31, 2017, divided by (b) three. Such amount will be increased annually by 2.5% which began on December 31, 2017.

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

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“FASB” Financial Accounting Standards Board.

“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.

“February 2018 distribution” The cash distribution to Trust unitholders of record on February 19, 2018 that was paid on March 1, 2018.

“February 2019 distribution” The cash distribution to Trust unitholders of record on February 19, 2019 that was paid on March 1, 2019.

“February 2020 distribution” The cash distribution to Trust unitholders of record on February 19, 2020 that was paid on February 28, 2020.

“field” An area consisting of 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 2017 distribution” The cash distribution to Trust unitholders of record on May 20, 2017 (which resulted in an effective record date of May 19, 2017 due to the 20th of May falling on a non‑trading day) that was paid on May 30, 2017.

“May 2018 distribution” The cash distribution to Trust unitholders of record on May 20, 2018 (which results in an effective record date of May 18, 2018 due to the 20th of May falling on a non-trading day) that was paid on May 30, 2018.

“May 2019 distribution” The cash distribution to Trust unitholders of record on May 20, 2019 that was paid on May 30, 2019.

“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 British Thermal Units, used in reference to natural gas.

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

“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.

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

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

“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.

“NGL” Natural gas liquid.  

“November 2017 distribution” The cash distribution to Trust unitholders of record on November 19, 2017 (which resulted in an effective record date of November 17, 2017 due to the 19th of November falling on a non‑trading day) that was paid on November 29, 2017.

“November 2018 distribution” The cash distribution to Trust unitholders of record on November 19, 2018 that was paid on November 29, 2018.

“November 2019 distribution” The cash distribution to Trust unitholders of record on November 19, 2019 that was paid on November 29, 2019.

“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 most 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, transportation, gathering, compression and other expenses,  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.

“probabilistic method” The method of estimating reserves using the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) to generate a full range of possible outcomes and their associated probabilities of occurrence.

“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 or operating of the affected well.

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

“SEC” The United States Securities and Exchange Commission.

“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 on the average price during the 12‑month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first‑day‑of‑the‑month price for each month within such period (unless prices

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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 associated risks.

“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 601 Travis Street, 16th Floor,  Houston, Texas 77002. The telephone number of the Trustee is 512‑236‑6599.

The Trust makes copies of its reports under the Exchange Act available at http://whitingwhz.investorhq.businesswire.com. The Trust’s filings under the Exchange 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 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 of the United States. The underlying properties include interests in 1,305 gross (368.3 net) producing oil and gas wells as of December 31, 2019. Whiting completed an initial public offering of Trust units selling all of its 18,400,000 units on March 28, 2012. The Trust units are currently traded on the OTC, operated by OTC Markets Group, under the trading symbol “WHZT,” but the Trust can provide no assurance that any trading market for the Trust units will exist on the OTC in the future or that current trading levels will be sustained or will not diminish.

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. After the termination of the Trust, it will pay no further distributions.

As of December 31, 2019,  on a cumulative accrual basis 9.95 MMBOE (94%)  of the 10.61 MMBOE attributable to the NPI have been produced and sold or 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 of December 31, 2019, which is referred 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 divested as of December 31, 2019 is projected to be produced from the underlying properties prior to December 31, 2021,  which reserve report is based on NYMEX oil and gas prices of $55.69 per Bbl and $2.58 per MMBtu, respectively, pursuant to current SEC and FASB guidelines and the other assumptions included therein. The average NYMEX oil and gas prices for the month of February 2020 were $50.54 per Bbl and $1.85 per MMBtu, respectively.  Refer to “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, 2019 was approximately 83%  oil and approximately 17% 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, 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 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

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unitholders would be liable for the excess costs. The Trust, however, would not receive any net proceeds until future net proceeds exceed the total of those excess costs, plus interest at the prevailing money market rate. For more information on the net proceeds calculation, refer to “Computation of Net Proceeds” later in this section.

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 the 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 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 and sales points. 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, 2019,  2018 and 2017. 

	2019	2018	2017
Plains Marketing, L.P.	18%	20%	17%
Chevron USA	16%	16%	15%
Merit Management Partners I, LP (previously Marathon Oil Corporation)	13%	13%	14%
Sunoco, Inc.	10%	4%	3%
Phillips 66 Company	9%	9%	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

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natural gas at any price to attempt to maintain cash flow. The Trust is subject to the same competitive conditions as Whiting and other companies in the oil and natural gas industry.

Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal, wind, solar, nuclear 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 makes available 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 General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware would give effect to such limitation.

Voting Rights of Trust Unitholders

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

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.

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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 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. After the termination of the Trust, it will pay no further distributions and the market price of Trust units will have declined to zero.  The remaining reserve quantities are projected to be produced prior to December 31, 2021, based on the Trust’s reserve report as of December 31, 2019.  As a result, the Trust is not currently expected to contractually terminate until December 31, 2021, and additional reserves and production attributable to the NPI may be available for distribution to unitholders between the time that the Trust’s minimum 10.61 MMBOE have been produced and sold and the Trust’s expected termination. However, there is no assurance that this will occur.

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

· the Trust sells the NPI;

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

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

· the Trust is judicially dissolved.

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

Computation of Net Proceeds

The provisions of the conveyance governing the computation of net proceeds are detailed and extensive. The following information summarizes the material information contained in the conveyance related to the 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 NPI was conveyed to the Trust by Whiting Oil and Gas on  March 28, 2012 by means of a conveyance instrument that has been recorded in the appropriate real property records in each county where the underlying properties are located. The NPI burdens the interests owned by Whiting in the underlying properties.

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

The amounts paid to the Trust for the NPI are based on the definitions of “gross proceeds” and “net proceeds” contained in the conveyance and described below. Under the conveyance, net proceeds are computed quarterly, and 90% of the aggregate net proceeds, 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.

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“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‑consent operations;

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

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

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

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

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

All of the hedge payments received by Whiting from the 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.

The capital expenditures included in the net proceeds attributable to the underlying properties are subject to an annual limitation that became effective January 1, 2018.  As a result, the sum of the capital expenditures and amounts reserved for approved capital expenditure projects for each year beginning in 2018 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 years ended December 31, 2017, divided by (y) three, which amount equals $3.9 million and will be increased annually by 2.5% to account for expected increased costs due to inflation. The capital expenditures incurred during 2019 and 2018 did not exceed the annual limitation, and capital expenditures included in the net proceeds attributable to the underlying properties cannot exceed $4.2 million during the year ending December 31, 2020.

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 $370 per month per active operated well, which totaled $1.3 million for the four distributions made during the year ended December 31, 2019. 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 attributable to the Trust’s interest in the NPI,  plus accrued interest at the prevailing money market rate, will be deducted from gross proceeds in the subsequent payment periods until all such negative amounts have been repaid.

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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 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. Whiting in turn conveyed the rights and obligations of such costless collar hedge contracts to the Trust.  All costless collar hedge contracts terminated as of December 31, 2014. Accordingly, there were no hedge contracts in place during any period presented in this Annual Report on Form 10‑K. 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.

Additional Provisions

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

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

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

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

The Trustee is not obligated to return any cash received from the NPI. Any overpayments made to the Trust by Whiting due to adjustments to prior calculations of net proceeds or otherwise will reduce future amounts payable to the Trust until Whiting recovers the overpayments plus interest at the prevailing money market rate. Whiting may make such adjustments to prior calculations of net proceeds without the consent of the Trust unitholders or the Trustee, but is required to provide the Trustee with notice of such adjustments and supporting data.

In addition, Whiting may, without the consent of the Trust unitholders, require the Trust to sell the net profits interest associated with any well or lease that accounts for less than or equal to 0.25% of the total production from the underlying properties in the prior 12 months, provided that the net profits interest covered by such releases cannot exceed, during any 12‑month period, an aggregate fair market value to the Trust of $1.0 million. These releases will be made only in connection with a sale by Whiting of the relevant underlying properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such portion of the NPI. Any net sales proceeds paid to the Trust are distributable to Trust unitholders in the quarter in which they are received. During 2019, Whiting had no divestitures of Trust properties.

For the underlying properties for which Whiting is the designated operator,  it may enter into farm‑out, operating, participation and other similar agreements with respect to the property. Whiting may enter into any of these agreements without the consent or approval of the Trustee or any Trust unitholder. Whiting entered into three farm‑out agreements with a third‑party partner for certain underlying properties within the (i) Keystone South field located in Winkler County, Texas in April 2016, (ii) Signal Peak field located in Howard County, Texas in February 2017, as amended in May 2018,  September 2019 and February 2020 and (iii) Flying W, SE field located in Winkler County, Texas in March 2017. 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.

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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 to claim its proportionate share of the deductions and expenses attributable to the assets of the Trust, subject to applicable limitations, in accordance with the Trust unitholder’s tax method of accounting and taxable year without regard to the taxable year or accounting method employed by the Trust.

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

Classification of the Net Profits Interest

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

Reporting Requirements for Widely‑Held Fixed Investment Trusts

Some Trust units are held by middlemen, as such term is broadly defined in the Treasury regulations (and includes custodians, nominees, certain joint owners and brokers holding an 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., 601 Travis Street, 16th Floor, Houston, Texas 77002, 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

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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 2019 federal and state income tax returns. The projected payment schedule for the NPI is included with the tax information booklet. This tax information booklet can be obtained at http://whitingwhz.investorhq.businesswire.com.

On December 22, 2017, Congress passed the Tax Cuts and Jobs Act (the “TCJA”). The new legislation significantly changes the U.S. corporate tax law by, among other things, lowering the highest marginal U.S. federal income tax rate applicable to corporations from 35% to 21% beginning in January 2018 which rate applies to both ordinary income and capital gains. Additionally, the TCJA lowers the highest marginal U.S federal income tax rate applicable to ordinary income of individuals from 39% to 37%. 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%.

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

Environmental Matters and Regulation

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

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

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

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

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

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

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

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

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

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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. Additionally, various federal, state and local agencies have jurisdiction over transportation, storage, and disposal of hazardous waste and seek to regulate movement of hazardous waste in ways not preempted by federal law. In its operations at the underlying properties, Whiting generates solid and hazardous wastes that are subject to RCRA and comparable state laws. Drilling fluid, produced water and many other wastes associated with the exploration, development and production of crude oil or natural gas are currently exempt from RCRA’s hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non‑hazardous could be regulated as hazardous waste in the future. In September 2010, the Natural Resources Defense Council filed a petition with the EPA, requesting it to reconsider the RCRA hazardous waste exemption for exploration, production and development wastes. In December 2016, the court entered a Consent Decree resolving the litigation, under which the EPA would issue such a rulemaking or make a determination that it was not necessary by March 15, 2019. In response, in April 2019, the EPA issued a determination that rulemaking to address waste from oil and gas exploration and production operations was not necessary at this time. However, it is possible that the EPA will take up such regulatory changes at a later date. 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 for sites contaminated by certain hazardous substances on classes of potentially responsible persons. 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 uses, generates or handles 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.

The underlying properties of the Trust may have been used for oil and natural gas exploration and production for many years. Although Whiting believes that it has utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties, or on or under other locations, including off‑site locations, where such substances have been taken for recycling or disposal. In addition, the underlying properties of the Trust may have been previously owned or operated by third parties whose treatment and disposal of hazardous substances, wastes or hydrocarbons and materials was not under Whiting’s control and not known to Whiting. 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 investigate the source and extent of impacts from released hazardous substances, 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 waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non‑compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons 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 drilled on the underlying properties, and Whiting expects it will also be used in the future. The process is typically regulated at the state level; however, the EPA issued guidance in 2014 to address hydraulic fracturing injections using diesel.

In addition, in June 2016, the EPA issued a final rule promulgating pretreatment standards for discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly‑owned treatment works. The EPA, along with other federal agencies

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such as the U.S. Department of Energy, the U.S. Government Accountability Office, the U.S. Department of Interior and the White House Council for Environmental Quality continue to study various aspects of hydraulic fracturing.

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. Multiple states, including Texas, Colorado and Wyoming have already adopted rules requiring disclosures of chemicals used in hydraulic fracturing and others have enacted regulations imposing additional requirements on activities involving hydraulic fracturing. Chemical disclosure regulations may increase compliance costs and may limit an operator’s ability to use cutting-edge technology in markets where disclosure is required. Further, laws such as those restricting the use of or regulating the time, place and manner of hydraulic fracturing (such as setback ordinances) may impact the operator’s ability to fully extract reserves. No assurance can be given as to whether or not such measures might be adopted 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.

In addition, in July 2014, a major university and U.S. Geological Survey researchers published a study purporting to find a 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 (“GHG”) 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 GHG under existing provisions of the federal Clean Air Act, as amended (“CAA”).

At present, the EPA may establish GHG permitting requirements for stationary sources already subject to the Prevention of Significant Deterioration (“PSD”) and Title V requirements of the CAA. 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 GHG. For any equipment or installation so subject, Whiting may have to incur increased compliance costs to capture related GHG 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 GHG for PSD and Title V permitting requirements. The public comment period for the rulemaking concluded on December 16, 2016. However, although the rulemaking remains on the EPA’s long-term regulatory agenda, no final rule has been published.

In August 2015, the EPA issued a rule to reduce carbon emissions from electric generating units. The rule, commonly called the “Clean Power Plan,” required 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. However, in February 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan while it was being challenged in court. On October 16, 2017, the EPA published a proposed rule that would repeal the Clean Power Plan and on August 18, 2018, the EPA proposed the Affordable Clean Energy (“ACE”) rule as a replacement to the Clean Power Plan. The EPA issued the final ACE rule in June 2019. As expected, over 20 states and public health and environmental organizations have challenged the rule. The EPA has sought expedited review in the hopes that the cases will be resolved by the summer of 2020. If the ACE rule were to become final, the costs of compliance are expected to be significantly less than they would have been under the Clean Power Plan.

In addition, both houses of Congress have actively considered legislation to reduce emissions of GHG, and many states have already taken legal measures to reduce emissions of GHG, primarily through the development of GHG inventories, 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. Also, in recent years, lawsuits have been brought against other energy companies for matters relating to climate change. Multiple states and localities have also initiated investigations in climate-change related matters. While the current suits focus on a variety of issues, at their core they seek compensation for the effects of climate change from companies with ties to emissions. It is currently unknown what the outcome of these types of actions may be, but the costs

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of defending such actions may be expected to rise. Finally, it should be noted that many scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events.

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. Federal and state regulatory agencies can impose penalties for non‑compliance with air permits or other requirements of the CAA and associated state laws and regulations.

In May 2016, the EPA issued a final rule regulating methane emissions from oil and natural gas operations (the “Subpart OOOOa Rule”). This rule applies to emissions from new, reconstructed and modified processes and equipment and also requires owners and operators to find and repair leaks to address fugitive emissions.

Certain states have also adopted, or are considering, regulations addressing methane releases from oil and gas operations. Colorado has adopted regulations reducing methane emissions from oil and gas operations. Compliance with rules applicable to jurisdictions in which the Trust’s underlying properties are located could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact cash distributions to unitholders.

However, in September 2019, the EPA proposed two alternative amendments to the Subpart OOOOa Rule. Both amendments would remove all methane-specific requirements from production and processing segments. The first amendment would also remove transportation and storage facilities from the definition of covered facilities. The comment period for the proposed rule closed on November 25, 2019. The net effect of either of these amendments, if finalized, would significantly reduce compliance obligations and associated costs.

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

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

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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, 2019 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 2020 with respect to these properties. However, there is no assurance that the passage of more stringent laws or implementing regulations in the future will not have a negative impact on the operations of these properties and the cash distributions to the Trust unitholders.

Item 1A. Risk Factors

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

The trading price for publicly traded securities similar to the Trust units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the Trust will vary in response to numerous factors outside the control of the Trust, including prevailing sales prices of oil, natural gas and natural gas liquids production attributable to the underlying properties. Further, the market price of Trust units may be affected by factors other than the anticipated future Trust distributions. Consequently, the market price for the Trust units may not necessarily be indicative of the value that the Trust would realize if it sold the NPI to a third‑party buyer. In addition, such market price may not necessarily reflect the fact that since the assets of the Trust are depleting assets, a portion of each cash distribution paid, 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 around or shortly after the NPI termination date, which is currently estimated to be December 31, 2021 based on the reserve report as of December 31, 2019.

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 less the costs to operate such properties. The reserves attributable to the underlying properties are depleting assets, which means that such reserves will decline over time. Based on the reserve report, overall production for both oil and gas attributable to the underlying properties is expected to decline at an average year‑over‑year rate of approximately 8.5% for oil and 13.6% for gas between 2020 and 2021, assuming the level of developmental drilling and investments on the underlying properties as assumed in the year‑end reserve report. However, cash distributions to unitholders may decline at a faster rate than the rate of production due to fixed and semi‑variable costs attributable to the underlying properties or if expected future development is delayed, reduced or cancelled. Also, the anticipated rate of decline is an estimate and actual decline rates will likely vary from those estimated. As of December 31, 2019, the percentage of remaining reserves expected to be produced during the term of the NPI was 17.5%. 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 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.

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

The amount 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, including Saudi Arabia’s decision in March 2020 to abandon output restraints in response to Russia’s refusal to make production cuts;

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

· market demand and capacity limitations on exports of oil and natural gas;

· political and economic conditions, including embargoes and sanctions, in oil‑producing countries or affecting other oil‑producing activity, such as the U.S. imposed sanctions on Venezuela and Iran and conflicts in the Middle East;

· developments of North American energy infrastructure;

· the occurrence or threat of epidemic or pandemic diseases, such as the recent outbreak of COVID-19, or any government response to such occurrence or threat;

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

· the effects of global conservation and sustainability measures;

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

· the effects of global and domestic economy, including the impact of expected growth, access to credit, financial and other economic issues;

· weather conditions;

· technological advances affecting energy consumption;

· current and anticipated changes to domestic and foreign governmental regulations, such as regulation of oil and natural gas gathering and transportation, including those that may arise as a result of the upcoming U.S. Presidential election;

· the price and availability of competitors’ supplies of oil and natural gas;

· basis differentials associated with market conditions, the quality and location of production and other factors;

· acts of terrorism;

· the price and availability of alternative fuels; and

· acts of force majeure.

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. 

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 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.

Oil prices have declined sharply in the first quarter of 2020 in response to the economic effects of the recent announcements by Saudi Arabia to abandon output restraints and the COVID-19 pandemic.  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, which could materially reduce or completely eliminate the amount of cash available for distribution to Trust unitholders, and may ultimately reduce the amount

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

The Trust units have been delisted from the New York Stock Exchange and are traded on the OTC market. It will likely be more difficult for unitholders 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 and transitioned to the OTC market, 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 the 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. Unitholders may find it difficult to resell their Trust units due to the delisting.

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 $55.69 per Bbl and $2.58 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, 2019, 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 be produced from the underlying properties prior to December 31, 2021. As basis for comparison, the estimated date when such amount would have been produced according to  the 2016 year‑end reserve report was July 31, 2023. However, the exact rate of production cannot be predicted with certainty and such amount may be produced before or after that date. If production attributable to the underlying properties is slower than estimated, then financial returns to purchasers of Trust units will be lower (assuming constant prices) because cash distributions attributable to such production will occur at a later date.

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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 fourth quarterly payment period of 2015 and the first and second quarterly payment periods of 2016.

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 fourth quarterly payment period of 2015 and the first quarterly payment period of 2016 when the NPI generated an aggregate $1.3 million net loss attributable to the Trust’s interest in the NPI, 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.

Should the Trustee determine 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 the Trust’s liabilities. However, Whiting’s ability to loan funds to the Trust is dependent on Whiting’s financial position. For a  discussion on Whiting’s financial position, refer to the risk factor entitled “If the financial position of Whiting degrades in the future, Whiting may not be able to satisfy its obligations to the Trust.”

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. The Trust does not maintain any type of insurance against any of the risks of conducting oil and gas exploration and production, hydraulic fracturing operations or related activities.

Also, Whiting’s oil, natural gas liquids and natural gas production depends in large part on the proximity,  capacity and ongoing operation of pipeline systems, transportation facilities and processing plants, which are mostly owned by third parties. The lack of availability or the lack of capacity on these systems,  facilities and plants could result in the curtailment of production or the delay or discontinuance of drilling plans, as occurred as a result of the permanent shutdown of the third-party operated Chatom Gas Plant in November 2019, which impacts underlying property wells located in the Lake Como field. 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, accidents 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.

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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.

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 66% of the underlying properties based on the standardized measure of discounted future net cash flows at December 31, 2019. The conveyance provides that Whiting will be obligated to market, or cause to be marketed, the production related to the 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 financial, business and other factors, many of which are beyond the control of Whiting. For the year ended December 31, 2019, Whiting reported a net loss of $241 million, and as of December 31, 2019 had outstanding indebtedness of $2.8 billion, of which $262 million is due in April 2020 and $774 million is due in March 2021 according to the Form 10-K for the year ended December 31, 2019 filed on February 27, 2020 by 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. If the reduced demand for crude oil in the global market as a result of the economic effects of the outbreak of COVID-19, and the recent reduction in the benchmark price of crude oil due in part to the recent announcement of Saudi Arabia’s abandonment of output restraints, persists for the near future or longer, or if the outbreak adversely affects employees of Whiting and such employees’ ability to conduct Whiting’s operations, such factors could have a negative impact on the financial condition and economic performance of Whiting.

The bankruptcy of operators could impede the operation of wells.

The value of the NPI and the Trust’s ultimate cash available for distribution is highly dependent on the financial condition of the operators of the wells. The ability to operate the underlying properties depends on all operators’ future financial condition and economic performance and access to capital, which in turn will depend upon the supply and demand for oil, natural gas and NGLs, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of such operators. If the reduced demand for crude oil in the global market as a result of the economic effects of the outbreak of COVID-19, and the recent reduction in the benchmark price of crude oil due in part to the recent announcement of Saudi Arabia’s abandonment of output restraints, persists for the near future or longer, such factors could have a negative impact on the financial condition and economic performance of the operators of the underlying properties.

In the event of any future bankruptcy of Whiting or any other operator of the underlying properties, the value of the NPI could be adversely affected by, among other things, delay or cessation of payments under the NPI, business disruptions or cessation of operations by the operator, replacements of operators, inability to find a replacement operator if necessary, reduced production of reserves or decreased distributions to Trust unitholders.

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, thereby possibly relieving Whiting from its obligations to make payments to the Trust with respect to the NPI.

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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 66% of the underlying properties based on the standardized measure of discounted future net cash flows at December 31, 2019. However, for the 34% 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.

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;

· pipeline takeaway and refining and processing capacity;

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

· equipment failures or accidents;

· adverse weather events, such as floods, blizzards, ice storms, tornadoes and freezing temperatures; and

· title defects.

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 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. The process is typically regulated at the state level, however, the EPA issued guidance in 2014 to address hydraulic fracturing injections involving diesel.

In addition, in June 2016 the U.S. Environmental Protection Agency (“EPA”) issued a final rule promulgating pretreatment standards for discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly owned treatment works.

The EPA, along with other federal agencies such as the U.S. Department of Energy, the U.S. Government Accountability Office, the U.S. Department of Interior and the White House Council for Environmental Quality continue to study various aspects of hydraulic fracturing.

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. Multiple states, including Texas, Colorado and Wyoming have

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already adopted rules requiring disclosures of chemicals used in hydraulic fracturing and others have enacted regulations imposing additional requirements on activities involving hydraulic fracturing. Chemical disclosure regulations may increase compliance costs and may limit our ability to use cutting-edge technology in markets where disclosure is required. Further, laws such as those restricting the use of or regulating the time, place and manner of drilling or hydraulic fracturing (such as setback ordinances) may impact our ability to fully extract reserves. No assurance can be given as to whether or not such 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 the operator of any of the underlying properties to perform hydraulic fracturing activities on the underlying properties.

In addition, in July 2014, a major university and U.S. Geological Survey researchers published a study purporting to find a 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.

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.

Weaker price differentials and/or weaker 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 or positive difference between the benchmark price and the price received is called a differential. The differential 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. Changes in the differential and decreases in the benchmark price for oil and natural gas could reduce cash distributions by the Trust and the value of the Trust units, as recently occurred when a significant increase in the differential for certain properties located in Wyoming and Texas impacted the February 2019 distribution.

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 wide

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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.

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.

Issues surrounding climate change and greenhouse gas emissions 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 (“GHG”) 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 GHG under existing provisions of the federal Clean Air Act, as amended (the “CAA”).

At present, the EPA may establish GHG permitting requirements for stationary sources already subject to the Prevention of Significant Deterioration (“PSD”) and Title V requirements of the CAA. 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 GHG. For any equipment or installation so subject, Whiting may have to incur increased compliance costs to capture related GHG 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 GHG for PSD and Title V permitting requirements. The public comment period for the rulemaking concluded on December 16, 2016. However, although the rulemaking remains on the EPA’s long-term regulatory agenda, no final rule has been published.

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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. However, in February 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan while it was being challenged in court. On October 16, 2017, the EPA published a proposed rule that would repeal the Clean Power Plan and on August 18, 2018, the EPA proposed the Affordable Clean Energy (“ACE”) rule as a replacement to the Clean Power Plan. The EPA issued the final ACE rule in June 2019. As expected, over 20 states and public health and environmental organizations have already challenged the rule. The EPA sought expedited review in the hopes that the cases will be resolved by the summer of 2020.

In addition, both houses of Congress have actively considered legislation to reduce emissions of GHG, and many states have already taken legal measures to reduce emissions of GHG, primarily through the development of GHG inventories, 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.

Also, in recent years, lawsuits have been brought against other energy companies for matters relating to climate change. Multiple states and localities have also initiated investigations in climate-change related matters. While the current suits focus on a variety of issues, at their core they seek compensation for the effects of climate change from companies with ties to GHG emissions. It is currently unknown what the outcome of these types of actions may be, but the costs of defending against such actions may rise. Finally, many scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the Trust’s assets and the amount of cash available for distribution to 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 oil field equipment as demand 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 oil field 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 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 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 years ended December 31, 2019, 2018 and 2017, the Trust received cash proceeds of $9.1 million, $18.9 million, and  $6.7 million, respectively, from the net profits interest. 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

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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.

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.

Whiting depends on computer and telecommunications systems, and failures in its systems or cyber security attacks could significantly disrupt its business operations.

Whiting has become increasingly dependent upon digital technologies to conduct day-to-day operations, including information systems, infrastructure and cloud applications. Whiting has entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with its business. In addition, Whiting has developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. Whiting relies on these systems to process, transmit and store electronic information, including financial records and personally identifiable information such as contractor, investor and payroll data, and to manage or support a variety of business processes, including its supply chain, pipeline operations, gathering and processing operations, financial transactions, banking and numerous other processes and transactions.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also have increased in frequency. A cyber-attack could include unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. It is possible that Whiting, or these third parties, could incur interruptions from cyber security attacks, computer viruses or malware, or that third party service providers could cause a breach of Whiting’s data. Whiting believes that it has positive relations with its related vendors and maintains adequate anti-virus and malware software and controls over personally identifiable information and contractor data; however, any interruptions to Whiting’s arrangements with third parties for its computing and communications infrastructure or any other interruptions to, or breaches of, its information systems could lead to data corruption, communication interruption, loss of sensitive or confidential information or otherwise significantly disrupt Whiting’s business operations, which in turn, could have a negative impact on the Trust and cash distributions.

Strategic targets, such as energy-related assets and transportation assets, may be at greater risk of future cyber-attacks than other targets. The various procedures, facilities, infrastructure and controls utilized by Whiting to monitor these threats and mitigate its exposure to such threats are costly and labor intensive. There can be no assurance that these measures will be sufficient to prevent security breaches from occurring. Whiting does not maintain or expect to obtain specialized insurance for possible liability or loss resulting from a cyber- attack on its assets that may shut down all or part of its business. However, as cyber threats continue to evolve, Whiting may be required to expend significant additional resources to continue to modify or enhance its protective measures or to investigate and remediate any information security vulnerabilities. State and federal cybersecurity legislation could also impose new requirements, which could increase costs.  

To Whiting’s knowledge, Whiting has not experienced any material losses relating to cyber-attacks; however, there can be no assurance that Whiting will not suffer material losses in the future either as a result of an interruption to or a breach of its systems or those of its third party vendors and service providers, and any such interruption or breach could have a material adverse effect on the Trust.

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Cyber security attacks or other failures in telecommunications or information technology systems could result in information theft, data corruption and significant disruption of the Trustee’s operations.

The Trustee depends heavily upon information technology systems and networks in connection with its business activities. Despite a variety of security measures implemented by the Trustee, events such as the loss or theft of back-up tapes or other data storage media could occur, and the Trustee’s computer systems could be subject to physical and electronic break-ins, cyber-attacks and similar disruptions from unauthorized tampering, including threats that may come from external factors, such as governments, organized crime, hackers and third parties to whom certain functions are outsourced, or may originate internally from within the respective companies.

If a cyber-attack were to occur, it could potentially jeopardize the confidential, proprietary and other information processed and stored in, and transmitted through, the Trustee’s computer systems and networks, or otherwise cause interruptions or malfunctions in the operations of the Trust, which could result in litigation, increased costs and regulatory penalties. Although steps are taken to prevent and detect such attacks, it is possible that a cyber incident will not be discovered for some time after it occurs, which could increase exposure to these consequences.

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

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

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

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

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

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

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

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

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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.

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 located primarily in the Permian Basin, Rocky Mountains, Gulf Coast and Mid‑Continent regions of the United States. The underlying properties include interests in 1,305 gross  (368.3 net) producing oil and natural gas wells located in 44 predominately mature fields with established production profiles in 10 states. As of December 31, 2019,  100% of estimated proved reserves attributable to the Trust’s interest in the NPI were classified as proved developed producing. For the year ended December 31, 2019, the net production attributable to the underlying properties was 1,073 MBOE or 2,939 BOE/d. Whiting operates approximately 66% of the underlying properties based on the December 31, 2019 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 properties that are operated by Whiting are burdened by non‑working interests owned by third parties and royalty interests retained by the owners of the land subject to the working interests. The royalty interests typically entitle the landowner to receive at least 12.5% of the revenue derived from oil and natural gas production from wells drilled on the landowner’s land, without any deduction for drilling costs or other costs related to production of oil and natural gas. A working interest percentage represents a working interest owner’s proportionate ownership interest in a property in relation to all other working interest owners in that property, whereas a net revenue interest is a working interest owner’s percentage of production and revenues, after reducing such interest by the percentage of burdens on production such as royalties and overriding royalties.

The NPI entitles the Trust to receive 90% of the net proceeds from the sale of at least 11.79 MMBOE (10.61 MMBOE at the 90% NPI) of production from the underlying properties.  As of December 31, 2019, on a cumulative accrual basis 9.95 MMBOE (94%) of the 10.61 MMBOE attributable to the NPI have been produced and sold or divested. The remaining minimum reserve balance of 0.66 MMBOE (at the 90% NPI) is projected to be produced prior to December 31, 2021, based on the Trust’s year‑end 2019 reserve report. Accordingly, the Trust’s remaining reserves attributable to the 90% NPI were estimated to be 1.52 MMBOE as of December 31, 2019, which is more than the minimum, but there is no assurance that the Trust will receive more than the minimum amount of reserves. However, the reserve report is based on the assumptions included therein. Refer to “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 the currently projected date. The proved reserves attributable to the underlying properties include all proved reserves expected to be economically produced during the remaining full life of the properties, whereas the Trust is only entitled to receive 90% of the net proceeds from the sale of production of oil, natural gas and natural gas liquids attributable to the underlying properties during the term of the NPI.

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

In general, the producing wells to which the underlying properties relate have established production profiles. Based on the reserve report, annual production from the underlying properties is expected to decline at an average year‑over‑year rate of approximately 8.5% for oil and 13.6% for gas from 2020 through the estimated December 31, 2021 NPI termination date, assuming no additional developmental drilling or investments are made 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, 2019, all of the Trust’s  oil and gas reserves are attributable to properties within the United States. The following table summarizes estimated proved reserves and the standardized measure of discounted future net cash flows as of December 31, 2019 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(4)				Underlying Properties(5)
	(90% NPI through December 2021)(6)				(100% Full Economic Life)
	Oil(7) (MBbl)	Natural Gas (Mcf)	MBOE		Oil(7) (MBbl)	Natural Gas (Mcf)	MBOE
Proved reserves(1):
Developed	1,331	1,142		1,522	8,448	7,120		9,635
Undeveloped(2)	-	-		-	-	-		-
Total proved—December 31, 2019	1,331	1,142		1,522	8,448	7,120		9,635
Standardized measure(3)			$	27,047			$	93,021

____________

(1) Oil and gas reserve quantities have been derived from NYMEX oil and gas prices of $55.69 per Bbl and $2.58 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, 2019, pursuant to current SEC and FASB guidelines. The average NYMEX oil and gas prices for the month of February 2020 were $50.54 per Bbl and $1.85 per MMBtu, respectively.

(2) This table does not include any proved undeveloped reserve quantities as of December 31, 2019 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 could meet the criteria of proved undeveloped reserves, such locations are not reflected in the December 31, 2019 reserve report because no future capital has been committed for the development of such reserves on the underlying properties.

(3) Standardized measure of discounted future net cash flows as of December 31, 2019. 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.

(4) The Trust’s estimated proved reserves as of December 31, 2019 on a 90% NPI basis were 1,522 MBOE, which reserve amount includes only those quantities of proved reserves in the underlying properties that are available to satisfy the interests of Trust unitholders and does not include the remaining 10% of proved reserves in the underlying properties to which only Whiting would be entitled.

(5) 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 only entitled to receive 90% of the net proceeds from the sale of production of oil, natural gas and natural gas liquids attributable to the underlying properties during the term of the NPI.

(6) 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, 2019 reserve report projects that the underlying properties will produce the Trust’s minimum volumes prior to December 31, 2021. Since the net profits interest is not expected to contractually terminate until December 31, 2021, the December 31, 2019 reserve report includes 862 MBOE of additional reserves attributable to the 90% NPI in excess of the Trust’s minimum volumes.

(7) Oil includes natural gas liquids.

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 

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price for each month of 2019, 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, 2019. 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. Refer to “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’s interest in the NPI from January 1, 2019 to December 31, 2019, 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 Item 8 of 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 2019, revisions to previous estimates increased proved reserves by a net amount of 50 MBOE. Included in these revisions were (i) 26 MBOE of downward adjustments caused by lower oil and gas pricing incorporated into the Trust’s reserve estimates as of December 31, 2019 compared to December 31, 2018 and (ii) 76 MBOE of net upward adjustments attributable to reservoir analysis. 

Preparation of reserves estimates. Whiting has advised the Trustee that it maintains adequate and effective internal controls over the reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data. All field and reservoir technical information, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land personnel to discuss field performance. Current revenue and expense information is obtained from Whiting’s accounting records, which are subject to their own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using the criteria set forth in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as commodity prices, lease operating expenses, transportation, gathering, compression and other 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. The Trust’s primary contact at CG&A is Mr. W. Todd Brooker, President. Mr. Brooker is a State of Texas Licensed Professional Engineer.  Refer to 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 Director of Reservoir Engineering is responsible for overseeing the preparation of the reserves estimates. She has more than 25 years of broad reservoir engineering experience in the oil and gas industry, focused across conventional, unconventional and secondary recovery evaluation and development projects, including corporate reserves estimations. She holds a Bachelor of Science degree in petroleum engineering from Universidad Central de Venezuela, a Master of Science degree in reservoir engineering from Texas A&M University and a Master of Science degree in reservoir geoscience from the Institut Francais du Petrole. She is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation 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 prior to December 31, 2021. The exact rate of production attributable to the underlying properties cannot be accurately predicted as numerous uncertainties are inherent in estimating reserve volumes and values, and 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

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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, 2019:

	Number of	Developed Acreage		Undeveloped Acreage		Total Acreage
Region	Fields	Gross	Net	Gross	Net	Gross	Net
Permian Basin	16	24,390	19,326	5,834	3,676	30,224	23,002
Rocky Mountains	13	23,943	9,979	-	-	23,943	9,979
Gulf Coast	8	10,412	3,968	470	153	10,882	4,121
Mid-Continent	7	2,367	1,219	40	34	2,407	1,253
Total	44	61,112	34,492	6,344	3,863	67,456	38,355

The following is a summary of the producing wells on the underlying properties as of December 31, 2019:

	Operated Wells		Non-Operated Wells		Total Wells
	Gross	Net	Gross	Net	Gross	Net
Oil	273	246.0	957	92.5	1,230	338.5
Natural gas	30	25.4	45	4.4	75	29.8
Total	303	271.4	1,002	96.9	1,305	368.3

The following is a summary of the number of productive wells drilled on the underlying properties during the last three years.  There were no dry wells drilled on the underlying properties during the years ended December 31, 2019,  2018 and 2017.  A productive well is an exploratory, development or extension well that is not a dry well. A dry well is an exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or gas 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.

	Year Ended December 31,
	2019		2018		2017
	Gross	Net	Gross	Net	Gross	Net
Developmental
Oil wells	2	0.50	2	0.50	2	0.50
Natural gas wells	-	-	-	-	-	-
Exploratory
Oil wells	-	-	-	-	1	0.25
Natural gas wells	-	-	-	-	-	-
Total	2	0.50	2	0.50	3	0.75

As of December 31, 2019, no wells were in the process of being drilled or completed.

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Oil and Natural Gas Production

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

	Year Ended December 31,
	2019			2018		2017
Net sales volumes:
Oil production (MBbl)(1)		895			936		964
Natural gas production (MMcf)		1,063			1,206		1,220
Total production (MBOE)		1,073			1,137		1,168
Average daily production (MBOE/d)		2.9			3.1		3.2
Garland field sales volumes(2):
Oil production (MBbl)(1)		140			147		152
Natural gas production (MMcf)		31			40		41
Total production (MBOE)		145			154		159
Keystone field sales volumes(2):
Oil production (MBbl)(1)		157			148		139
Natural gas production (MMcf)		338			384		310
Total production (MBOE)		213			212		190
Rangely field sales volumes(2):
Oil production (MBbl)(1)		143	��		149		149
Natural gas production (MMcf)		-			-		-
Total production (MBOE)		143			149		149
Average sales prices:
Oil (per Bbl)(1)	$	50.07		$	53.91	$	44.35
Natural gas (per Mcf)	$	1.85		$	3.40	$	3.26
Average production costs:
Production costs per BOE(3)	$	29.88		$	24.65	$	26.12

____________

(1) Oil includes natural gas liquids.

(2) The Garland and Keystone fields were the only fields that contained 15% or more of the total proved reserve volumes of the underlying properties as of December 31, 2019 and 2018. The Garland, Keystone 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, 2017.

(3) Production costs reported above exclude from lease operating expenses ad valorem taxes of $1.5 million  ($1.40/BOE), $1.6 million  ($1.38/BOE) and $1.5 million  ($1.28/BOE) for the years ended December 31, 2019,  2018 and 2017, respectively.

Certain of the Trust’s wells are included in eight separate enhanced oil recovery waterflood projects, which include both secondary (waterflood) and tertiary (CO2 injection) recovery efforts. Aggregate production from such enhanced oil recovery fields averaged 1,135 BOE/d during 2019 or 39% of 2019 daily production from the underlying properties. For these areas, the operator 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, 2019, approximately 66% of these properties were operated by Whiting. Based on annual 2019 production attributable to the underlying properties, approximately 83% of production was crude oil and natural gas liquids and 17% 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.

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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 16 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, Wolfcamp, 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, 2019, the net production attributable to the underlying properties in this region was 499.8 MBOE or 1.3 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 13 fields of which Whiting operates wells in three.  The Trust’s NPI does not include any of Whiting’s interests in the Bakken and Three Forks formations. The major fields in this region include the Rangely field that produces from the Weber Sand zone; the Garland field that produces from the Madison and Tensleep zones; the Cedar Hills field that produces from the Red River zone; and the Whiting‑operated Torchlight field that produces from the Madison and Tensleep zones. For the year ended December 31, 2019, the net production attributable to the underlying properties in this region was 451.0 MBOE or 1.2 MBOE/d.

Gulf Coast Region. The underlying properties in the Gulf Coast region are located in Texas and Mississippi. These properties consist of eight onshore fields, and Whiting operates wells in four.  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, 2019, the net production attributable to the underlying properties in this region was 104.6 MBOE or 0.3 MBOE/d.

Mid‑Continent Region. The underlying properties in the Mid‑Continent region are located in Michigan, Arkansas, Oklahoma and Texas. These properties consist of seven fields of which Whiting operates wells in two.  The major field in this region is the Whiting‑operated Wesson field located in Arkansas that produces from the Hogg Sand zone. For the year ended December 31, 2019, the net production attributable to the underlying properties in this region was 17.3 MBOE or 0.1 MBOE/d.

Abandonment, Sale, and Farm‑out of Underlying Properties

Any operator of the underlying properties, including Whiting, has the right to abandon its interest in any well or property comprising a portion of the underlying properties if, in its opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities. To reduce the potential conflict of 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. In addition, 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, 2019,  2018 and 2017, there were zero,  five and seven gross wells, respectively, that were plugged and abandoned on the underlying properties, based on the determination that such wells were no longer economic to operate.

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, 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. No sales of oil and gas wells occurred during the years ended December 31, 2019, 2018 and 2017.  

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. In an effort to develop the underlying properties while limiting additional capital expenditures for the Trust, Whiting Oil and Gas entered into three farm‑out agreements with a third‑party partner covering (i) 5,127 gross acres in eight leasehold sections within the Keystone South field in Winkler, Texas in April 2016 (the “Keystone South farm‑out”), (ii) 9,740 gross acres in approximately 15 units (which unit size is determined by the lateral well length) within the Signal Peak field in Howard County, Texas in February 2017, as amended in May 2018,  September 2019 and February 2020 (the “Signal Peak farm‑out”) and (iii) 640 gross acres in one leasehold section within the Flying W, SE field in Winkler County, Texas in March 2017 (the “Flying W farm‑out”).

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These farm‑out agreements provide the third‑party partner with the option, but not the obligation, to drill one well in each of the leasehold sections or units, as the case may be, subject to the applicable farm‑out agreement, whereby the partner will pay 100% of the related drilling and well completion costs to earn a 75% working interest. As a result, the applicable underlying properties will consist of (i) 25% of the original working interest in these properties and (ii) an overriding royalty interest equal to the difference between 25% and the lease burdens of record. Upon completion of one well in each section or unit, as the case may be, pursuant to the terms of the applicable agreements, the partner has the option to drill (i) up to 15 additional wells under the Keystone South farm‑out, (ii) up to 12 additional wells under the Signal Peak farm‑out and (iii) one additional well under the Flying W farm‑out. For each of these additional optional wells,  the partner is required to pay 85% of the drilling and well completion costs otherwise ascribed to the underlying properties for a 75% working interest. Given the Trust’s interest in the NPI, the Trust would be responsible for 13.5% of the underlying properties’ remaining drilling and well completion costs at the 90% NPI, subject to the average annual capital expenditure amount limitation as described in the “Computation of Net Proceeds” section in Item I of this Annual Report on Form 10‑K.

The third-party partner drilled and completed the first three wells pursuant to the terms of the Keystone South farm-out agreement during 2017, a fourth well was drilled and completed during the second quarter of 2018, and a fifth well was drilled and completed during the fourth quarter of 2019, whereby the partner earned a 75% working interest in each of the underlying properties’ respective leasehold sections. The partner has no obligation to drill and complete any additional wells, and the Keystone South farm-out agreement will terminate during the third quarter of 2020 if no additional drilling has commenced by that time.

During the fourth quarter of 2019, the third-party partner drilled and completed the first well under the Signal Peak farm-out, whereby the partner earned a 75% working interest in the underlying properties’ respective leasehold section. The partner has no obligation to drill and complete any additional wells, and the Signal Peak farmout will terminate during the second quarter of 2020 if no additional drilling has commenced by that time.

In addition, the partner drilled and completed the first well under the Flying W farm-out during the second quarter of 2018, whereby the partner earned a 75% working interest in the underlying properties’ respective leasehold section.

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 value of the reserves attributable to the underlying properties.

Whiting’s interests in the oil and natural gas properties comprising the underlying properties are typically subject, in one degree or another, to one or more of the following:

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

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

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

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

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

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

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

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

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

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

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

The Trust units commenced trading on the New York Stock Exchange on March 23, 2012 under the symbol “WHZ” 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.” The Trust can provide no assurance that any trading market for the Trust units will exist on the OTC in the future or that current trading levels will be sustained or will not diminish.

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 for each quarter in 2019 and 2018 were as indicated in the table below as reported by the OTC. These quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

	Price Per Unit
	High		Low
Year Ended December 31, 2019
First quarter (January 1 through March 31)	$	1.96	$	1.39
Second quarter (April 1 through June 30)	$	1.88	$	1.01
Third quarter (July 1 through September 30)	$	1.26	$	0.90
Fourth quarter (October 1 through December 31)	$	0.95	$	0.04
Year Ended December 31, 2018
First quarter (January 1 through March 31)	$	1.54	$	1.11
Second quarter (April 1 through June 30)	$	3.80	$	1.30
Third quarter (July 1 through September 30)	$	3.16	$	1.70
Fourth quarter (October 1 through December 31)	$	2.95	$	1.00

At March 24, 2020, the 18,400,000 units outstanding were held by two unitholders of record.

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

None.

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Item 6. Selected Financial Data

The following table sets forth selected data based on the Trust’s audited financial statements  for the periods presented (in thousands, except distributable income per unit and Trust units outstanding data):

	Year Ended December 31,
	2019		2018		2017		2016			2015
Income from net profits interest	$	9,119	$	18,924	$	6,727	$	1,548	$	10,161
Distributable income	$	8,304	$	18,109	$	5,814	$	1,199	$	9,360
Distributable income per unit	$	0.451281	$	0.984171	$	0.315961	$	0.065170	$	0.508693

	Year Ended December 31,
	2019		2018		2017		2016			2015
Trust corpus	$	7,718	$	12,357	$	17,812	$	23,929	$	30,966
Total assets at year-end	$	7,920	$	12,638	$	18,189	$	24,113	$	31,245
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 of Operations

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 pursuant to the NPI, and to perform certain administrative functions with respect to the NPI and the Trust units. The Trust derives substantially all of its income and cash flows from the NPI. 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, 2019. The 2019 NPI distributions are mainly affected, however, by October 2018 through September 2019 oil prices and September 2018 through August 2019 natural gas prices.

	2017								2018								2019
	Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4
Crude oil	$	51.86	$	48.29	$	48.19	$	55.39	$	62.89	$	67.90	$	69.50	$	58.83	$	54.90	$	59.83	$	56.45	$	56.96
Natural gas	$	3.07	$	3.09	$	2.89	$	2.87	$	3.13	$	2.77	$	2.88	$	3.62	$	3.00	$	2.58	$	2.29	$	2.44

Oil prices have declined sharply during the first quarter of 2020 in response to the economic effects of the recent announcement of Saudi Arabia’s abandonment of output restraints and the COVID-19 pandemic. Continued low oil and gas prices on production from the underlying properties could cause (i) a reduction in the amount of net proceeds to which the Trust is entitled, which could materially reduce or completely eliminate the amount of cash available for distribution to Trust unitholders, (ii) a reduction in the amount of oil, natural gas and natural gas liquids that are economic to produce from the underlying properties, which could extend the length of time required to produce 11.79 MMBOE (10.61 MMBOE at the 90% NPI), and (iii) the recognition of impairment charges on the NPI.  All costless collar hedge contracts terminated as of December 31, 2014 and no additional hedges are allowed to be placed on the Trust assets. Consequently, there are no 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. Additionally, in the current commodity price environment, the Trust’s distributions have increased sensitivity to fluctuations in operating and capital expenditures, as was the case for the fourth quarter of 2017 and the first quarter of 2019.

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 December 31, 2021 based on the Trust’s year‑end 2019 reserve report or (b) the sale of the net profits interest. 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 is a return of capital to investors, 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 the termination of the Trust. As of December 31, 2019, on a cumulative accrual basis, 9.95 MMBOE (94%) of the 10.61 MMBOE attributable to the NPI have been produced and sold or divested.  The remaining minimum reserve quantities are projected to be produced prior to December 31, 2021, based on the Trust’s reserve report as of December 31, 2019. Accordingly, the Trust’s remaining reserves attributable to the 90% NPI were estimated to be 1.52 MMBOE as of December 31, 2019, which is more than the minimum, but there is no assurance that the Trust will receive more than the minimum amount of reserves. 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,  refer to “Description of the Underlying Properties” in Item 2  of this Annual Report on Form 10‑K.

For a discussion of material changes to the Trust’s proved reserves from December 31, 2018 to December 31, 2019,  refer to “Reserves” in Item 2 of this Annual Report on Form 10‑K. Additionally, for a discussion of the need to use enhanced recovery techniques, refer to  “Oil and Natural Gas Production” in Item 2 of this Annual Report on Form 10‑K.

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Capital Expenditure Activities

The primary goal of the planned capital expenditures relative to the underlying properties is to mitigate  a portion of the natural decline in production from producing properties. No assurance can be given, however, that any such expenditures will be made, or if made, will result in production in commercially paying amounts, if any, or that the characteristics of any newly developed well will match the characteristics of existing wells on the underlying properties or the operator’s historical drilling success rate. The underlying properties have a capital expenditure budget per the reserve report of $3.8 million estimated to be spent over the two years estimated to remain. No assurance can be given that the actual level of capital expenditures on the underlying properties will meet this  $3.8 million amount of budgeted capital expenditures over such time frame. With respect to fields for which Whiting is not the operator, Whiting has limited control over the timing and amount of capital expenditures relative to such fields.  Refer to the risk factor entitled  “Whiting has limited control over activities on the underlying properties that Whiting does not operate, which could reduce production from the underlying properties, increase capital expenditures and reduce cash available for distribution to Trust unitholders.” The following table summarizes the underlying properties’ planned capital expenditures per the reserve report for 2020 through the NPI termination date, which is currently estimated to be December 31, 2021:

	2020 - 2021 Planned Capital Expenditures(2)
	(in millions)		Gross Wells	Net Wells
Rocky Mountains Region:
Rangely field — CO2 and maintenance capital	$	2.6	-	-
Garland field — maintenance capital		1.2	-	-
Total(1)	$	3.8	-	-

____________

(1) The planned capital expenditures attributable to the Trust’s 90% net profits interest are $3.4 million.

(2) The planned capital expenditures for each of the two remaining years of the NPI are below the annual capital expenditure limitation, which limitation became effective January 1, 2018.

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, the estimated capital expenditures allocated to the underlying properties’ interest are approximately $1.3 million per year for 2020 and 2021 through the estimated termination of the NPI. Such capital costs are comprised mainly of CO₂ purchases and plant and equipment expenditures. During 2017, Chevron Corporation advised Whiting of a mandatory compliance‑driven inspection and maintenance project for the Rangely Weber Sand Unit, which commenced in June 2017 and was completed during July 2017. The cost of the project attributable to the underlying properties was $1.5 million ($1.4 million to the 90% NPI), the vast majority of which were capital expenditures. Whiting is not aware of any development plans by Chevron USA at this time, however, Chevron USA may propose 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 for 2020 and 2021, respectively, through the estimated termination of the NPI. Although Whiting is not aware of any development plans by this operator or other operators of the underlying properties in this region, these operators may propose additional 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.

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

Annual capital expenditure limitation. The capital expenditures included in the net proceeds attributable to the underlying properties are subject to an annual limitation which became effective January 1, 2018. As a result, the sum of the capital expenditures and amounts

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reserved for approved capital expenditure projects for each year beginning in 2018 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 years ended December 31, 2017, divided by (y) three,  which amount equals $3.9 million and will be increased annually by 2.5% to account for expected increased costs due to inflation. The capital expenditures incurred during 2019 and 2018 did not exceed this annual limitation, and capital expenditures included in the net proceeds attributable to the underlying properties cannot exceed $4.2 million during the year ending December 31, 2020.

Farm‑out agreements. In an effort to develop the underlying properties while limiting additional capital expenditures for the Trust (other than those capital expenditures already contemplated in the reserve report), Whiting Oil and Gas entered into three farm‑out agreements with a third‑party partner covering (i) 5,127 gross acres in eight leasehold sections within the Keystone South field in Winkler, Texas in April 2016 (the “Keystone South farm‑out”), (ii) 9,740 gross acres in approximately 15 units (which unit size is determined by the lateral well length) within the Signal Peak field in Howard County, Texas in February 2017, as amended in May 2018,  September 2019 and February 2020 (the “Signal Peak farm‑out”) and (iii) 640 gross acres in one leasehold section within the Flying W, SE field in Winkler County, Texas in March 2017 (the “Flying W farm‑out”).

These farm‑out agreements provide the third‑party partner with the option, but not the obligation, to drill one well in each of the leasehold sections or units, as the case may be, subject to the applicable farm‑out agreement, whereby the partner will pay 100% of the related drilling and well completion costs to earn a 75% working interest. As a result, the applicable underlying properties will consist of (i) 25% of the original working interest in these properties and (ii) an overriding royalty interest equal to the difference between 25% and the lease burdens of record. Upon completion of one well in each section or unit, as the case may be, pursuant to the terms of the applicable agreements, the partner has the option to drill (i) up to 15 additional wells under the Keystone South farm‑out, (ii) up to 12 additional wells under the Signal Peak farm‑out and (iii) one additional well under the Flying W farm‑out. For each of these additional optional wells, the partner is required to pay 85% of the drilling and well completion costs otherwise ascribed to the underlying properties for a 75% working interest. Given the Trust’s interest in the NPI, the Trust would be responsible for 13.5% of the underlying properties’ remaining drilling and well completion costs at the 90% NPI, subject to the average annual capital expenditure amount limitation discussed above.

The third-party partner drilled and completed the first three wells pursuant to the terms of the Keystone South farm-out agreement during 2017, a fourth well was drilled and completed during the second quarter of 2018, and a fifth well was drilled and completed during the fourth quarter of 2019, whereby the partner earned a 75% working interest in each of the underlying properties’ respective leasehold sections. The partner has no obligation to drill and complete any additional wells, and the Keystone South farm-out agreement will terminate during the third quarter of 2020 if no additional drilling has commenced by that time.

During the fourth quarter of 2019, the third-party partner drilled and completed the first well under the Signal Peak farm-out, whereby the partner earned a 75% working interest in the underlying properties’ respective leasehold section. The partner has no obligation to drill and complete any additional wells, and the Signal Peak farmout will terminate during the second quarter of 2020 if no additional drilling has commenced by that time.

In addition, the partner drilled and completed the first well under the Flying W farm-out during the second quarter of 2018, whereby the partner earned a 75% working interest in the underlying properties’ respective leasehold section.

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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 each respective period (dollars in thousands, except per Bbl, per Mcf and per BOE amounts):

Trust Results
	Year Ended December 31,
	2019			2018			2017
Sales volumes:
Oil from underlying properties (MBbl)(1)		917	(4)		955	(5)		965	(6)
Natural gas from underlying properties (MMcf)		1,111	(4)		1,307	(5)		1,220	(6)
Total production (MBOE)		1,103			1,173			1,168
Average sales prices:
Oil (per Bbl)(1)	$	48.40		$	54.28		$	42.42
Natural gas (per Mcf)(2)	$	2.30		$	3.29		$	3.18
Cost metrics:
Lease operating expenses (per BOE)	$	29.52		$	24.64		$	26.19
Production tax rate (percent of total revenues)		5.0	%		5.1	%		4.8	%
Revenues:
Oil sales(1)	$	44,407	(4)	$	51,827	(5)	$	40,931	(6)
Natural gas sales		2,558	(4)		4,296	(5)		3,883	(6)
Total revenues		46,965			56,123			44,814
Costs:
Lease operating expenses		32,555			28,900			30,595
Production taxes		2,328			2,887			2,132
Development costs		1,950			3,309			4,613
Cash settlements on commodity derivatives(3)		-			-			-
Total costs		36,833			35,096			37,340
Net proceeds		10,132			21,027			7,474
Net profits percentage		90	%		90	%		90	%
Income from net profits interest		9,119			18,924			6,727
Provision for estimated Trust expenses		(800)			(800)			(900)
Montana state income tax withheld		(15)			(15)			(13)
Distributable income	$	8,304		$	18,109		$	5,814

____________

(1) Oil includes natural gas liquids.

(2) The average sales price of natural gas for the gas production months within the years ended December 31, 2018 and 2017 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 year ended 2019 are still “liquids rich,” such liquids content did not result in a premium to the NYMEX natural gas price due to depressed liquids prices during that period.

(3) 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, 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.

(4) Oil and gas sales volumes and related revenues for the year ended December 31, 2019 (consisting of Whiting’s  February 2019,  May 2019,  August 2019 and November 2019 distributions to the Trust) generally represent crude oil production from October 2018 through September 2019 and natural gas production from September 2018 through August 2019.

(5) Oil and gas sales volumes and related revenues for the year ended December 31, 2018 (consisting of Whiting’s February 2018,  May 2018,  August 2018 and November 2018 distributions to the Trust) generally represent crude oil production from October 2017 through September 2018 and natural gas production from September 2017 through August 2018.

(6) Oil and gas sales volumes and related revenues for the year ended December 31, 2017 (consisting of Whiting’s February 2017, May 2017, August 2017 and November 2017 distributions to the Trust) generally represent crude oil production from October 2016 through September 2017 and natural gas production from September 2016 through August 2017.

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Comparison of Results of the Trust for the Years Ended December 31, 2019 and 2018

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 for which Whiting has received payment within one month following the end of the most recent fiscal quarter. Whiting receives payment for its crude oil sales generally within 30 days following the month in which it is produced, and Whiting receives payment for its natural gas sales generally within 60 days following the month in which it is produced. Income from net profits interest is generally a function of oil and gas revenues, lease operating expenses, production taxes and development costs as follows:

Revenues. Oil and natural gas revenues were $9.2 million (or 16%) lower in 2019 compared to 2018.  Sales revenue is a function of average commodity prices realized and oil and gas volumes sold.  The decrease in revenue between periods was primarily due to lower realized oil prices and a decline in oil production volumes. The average sales price realized decreased for crude oil and natural gas by 11% and 30%, respectively, between periods primarily as a result of lower NYMEX oil prices and rising natural gas differentials, which were partially offset by improved oil differentials.  Crude oil production volumes decreased by 38 MBbls (or 4%) between periods and natural gas volumes decreased by 196 MMcf (or 15%) in 2019 compared to 2018.  The slight oil volume decrease between periods was primarily related to normal field production decline, which was partially offset by two new wells that came online as a result of the Keystone South farm‑out agreement.  The decrease in gas volumes between periods was primarily due to (i) normal field production decline and (ii) one unit in the Warmsly South field and one well in the Keystone South field that were shut-in for all or a portion of 2019. The decrease in gas volumes was partially offset by one new well that came online as a result of the Keystone South farm-out agreement. Based on the December 31, 2019 reserve report, overall production attributable to the underlying properties is expected to decline at an average year‑over‑year rate of approximately 8.5% for oil and 13.6% for gas from 2020 through the estimated December 31, 2021  NPI termination date.

Lease Operating Expenses. LOE increased  $3.7 million (or 13%) during the year ended December 31, 2019 compared to the same 2018 period primarily due to a $4.2 million increase in oilfield goods and services, which includes an increase of $1.2 million in workover costs between periods. This increase was partially offset by (i) $0.5 million of lower labor and other operating costs on Whiting-operated properties and (ii) a $0.2 million decrease in ad valorem taxes between periods. The increase in overall LOE coupled with the decline in overall production volumes resulted in an increase in LOE on a per BOE basis of 20%  from $24.64 during 2018 to $29.52 for 2019.

Production Taxes. Production taxes are typically calculated as a percentage of oil and gas revenues. Production taxes as a percentage of revenues decreased from 5.1% during 2018 to 5.0% during 2019. Additionally, overall production taxes in 2019 decreased $0.6 million (or 19%) as compared to 2018 primarily due to lower oil and natural gas revenues between periods.  

Development Costs. Development costs were $1.4 million (or 41%) lower in 2019 as compared to 2018.  Development costs decreased primarily due to reduced drilling and capital workover costs between periods of $1.6 million in the Garland, Keystone South, Rangely, Deb and West Dickinson fields, which was partially offset by increased drilling and capital workover costs of $0.2 million in the Justis field.

Comparison of Results of the Trust for the Years Ended December 31, 2018 and 2017

For a  discussion of the Trust’s financial performance in the year ended December 31, 2018 compared to the year ended December 31, 2017, refer to Part II, Item 7 “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2018 Annual Report on Form 10-K filed with the SEC on March 22, 2019 under the subheading “Results of Trust Operations – Comparison of Results of the Trust for the Years Ended December 31, 2018 and 2017.” 

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 generates net losses or limited net proceeds (which was the case during the fourth quarter of 2017 and

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first quarter of 2019), 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 29,  2020, the Trust had cash reserves of $0.2 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. Such letter of credit is renewed annually during December for a one year term. As of December 31, 2019 and 2018, the Trust had no borrowings under the letter of credit.

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, 2019, 2018 and 2017. 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, 2019, Whiting incurred $0.9 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.

Contractual Obligations

The following table summarizes the Trust’s obligations and commitments as of December 31, 2019 to make future payments during the specified time periods (in thousands):

	Payments Due by Period(4)
Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years(4)
Delaware Trustee fees(1)	$	8	$	4	$	4	$	-
Trustee administrative service fees(2)		391		193		198		-
Whiting administrative service fees(3)		400		200		200		-
Total	$	799	$	397	$	402	$	-

____________

(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 annual administrative fee of $175,000 which is paid in four quarterly installments and is billed in arrears. Starting in 2017, such fee escalates by 2.5% each year.

(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 contractual obligation payments due are presented through the NPI termination date, which is currently estimated to be December 31, 2021 based on the reserve report as of December 31, 2019. The “3‑5 years” period represents obligations after the estimated December 31, 2021 NPI termination date. Actual amounts paid may differ from these estimates.

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New Accounting Pronouncements

There were no accounting pronouncements issued during the year ended December 31, 2019 applicable to the Trust or its financial statements.

Critical Accounting Policies and Estimates

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

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

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

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

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

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

While these statements differ from financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues and distributions is considered to be the most meaningful for the Trust and its results because quarterly distributions to the Trust unitholders are based on net cash receipts. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC, as specified by FASB ASC Topic 932, Extractive Activities – Oil and Gas:  Financial Statements of Royalty Trusts. For additional information regarding the Trust’s basis of accounting, refer to 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 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 to FASB and SEC guidelines. Such assumptions include using average fiscal‑year oil and gas prices (calculated as the unweighted arithmetic average of the first‑day‑of‑the‑month price for each month within the 12‑month reporting period)  and year‑end costs for estimated future production and development expenditures. Discounted future net cash flows are calculated using a 10% discount rate. Changes in any of these assumptions could have a significant impact on the standardized measure. The standardized measure does not necessarily result in an estimate of the current fair market value of proved reserves.

Amortization of Net Profits Interest. The investment in net profits interest is amortized using the units‑of‑production method. The rate of recording amortization is dependent upon the Trust’s 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 recorded would 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 based on the oil and gas reserves attributable to the underlying properties to the net book value at the end of each period. If the

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net capitalized cost exceeds undiscounted future cash flows, the cost of the investment in net profits interest is written down to “fair value,” which is determined using net discounted future cash flows from the net profits interest. Different pricing assumptions, discount rates, or oil and gas reserve estimates 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 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.

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 can be economically produced. 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,  all of which terminated as of December 31, 2014,  to manage the exposure to crude oil price volatility associated with revenues generated from the underlying properties, and to achieve more predictable cash flows. 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.

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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	49
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2019 and 2018	50
Statements of Distributable Income for the Years Ended December 31, 2019, 2018 and 2017	50
Statements of Changes in Trust Corpus for the Years Ended December 31, 2019, 2018 and 2017	50
Notes to Modified Cash Basis Financial Statements	51

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Unitholders of Whiting USA Trust II and

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

Opinion on the Financial Statements

We have audited the accompanying statements of assets, liabilities, and trust corpus of Whiting USA Trust II, (“the Trust”) as of December 31, 2019 and 2018, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2019, and related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the assets, liabilities, and trust corpus of the Trust as of December 31, 2019 and 2018, and its distributable income and its changes in trust corpus for each of the three years in the period ended December 31, 2019, in conformity with the modified cash basis of accounting described in Note 2.

Basis for Opinion

These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on the Trust’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting 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.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Basis of Accounting

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

/s/ Deloitte & Touche LLP

Austin, Texas

March 24, 2020

We have served as the Trust’s auditor since 2011.

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WHITING USA TRUST II

Statements of Assets, Liabilities and Trust Corpus

(In thousands, except unit data)

	December 31,
	2019		2018
ASSETS
Cash and short-term investments	$	202	$	281
Investment in net profits interest, net		7,718		12,357
Total assets	$	7,920	$	12,638
LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses	$	202	$	281
Trust corpus (18,400,000 Trust units issued and outstanding    as of December 31, 2019 and December 31, 2018)		7,718		12,357
Total liabilities and Trust corpus	$	7,920	$	12,638

Statements of Distributable Income

(In thousands, except distributable income per unit data)

	Year Ended December 31,
	2019		2018		2017
Income from net profits interest	$	9,119	$	18,924	$	6,727
General and administrative expenses		(879)		(896)		(707)
Cash reserves used (withheld) for current Trust expenses		79		96		(193)
State income tax withholding		(15)		(15)		(13)
Distributable income	$	8,304	$	18,109	$	5,814
Distributable income per unit	$	0.451281	$	0.984171	$	0.315961

Statements of Changes in Trust Corpus

(In thousands)

	Year Ended December 31,
	2019		2018		2017
Trust corpus, beginning of period	$	12,357	$	17,812	$	23,929
Distributable income		8,304		18,109		5,814
Distributions to unitholders		(8,304)		(18,109)		(5,814)
Amortization of investment in net profits interest		(4,639)		(5,455)		(6,117)
Trust corpus, end of period	$	7,718	$	12,357	$	17,812

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 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 of the United States (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, 2019, these oil and gas properties included interests in approximately 1,305 gross (368.3 net) producing oil and gas wells.

The NPI is passive in nature, and the Trustee has no management control over and no responsibility relating to the operation of the underlying properties. The NPI entitles the Trust to receive 90% of the net proceeds from the sale of production from the underlying properties. The 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. Once the Trust winds up its affairs and terminates, it will pay no further distributions.

As of December 31, 2019, on a cumulative accrual basis,  9.95 MMBOE (94%) of the 10.61 MMBOE attributable to the NPI have been produced and sold or divested. A cumulative 0.02 MMBOE of proved reserves have been divested through December 31, 2019.  The remaining minimum reserve balance of 0.66 MMBOE (at the 90% NPI) is projected to be produced prior to December 31, 2021, based on the Trust’s year‑end 2019 reserve report.

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 NPI and payments of expenses incurred. Actual cash distributions to the Trust are made based on the terms of the conveyance that created the Trust’s NPI. The 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; hedge payments received by Whiting under hedge contracts and other non‑production revenue) of the underlying properties multiplied by 90% (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

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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 of Royalty Trusts.

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

Cash and Short‑Term 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, 2019,  2018 and 2017.

	2019	2018	2017
Plains Marketing, L.P.	18%	20%	17%
Chevron USA	16%	16%	15%
Merit Management Partners I, LP (previously Marathon Oil Corporation)	13%	13%	14%
Sunoco, Inc.	10%	4%	3%
Phillips 66 Company	9%	9%	11%

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

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, 2019 applicable to the Trust or its financial statements.

3.   INVESTMENT IN NET PROFITS INTEREST

Whiting Oil and Gas conveyed the NPI to the Trust in exchange for 18,400,000 Trust units. The investment in net profits interest was recorded at the historical cost basis of Whiting on March 28, 2012, the date of conveyance (except for the derivatives which were reflected at their fair value as of March 31, 2012),  which was determined to be $194.0 million. However, such historical cost basis has been subject to impairments taken in prior periods. No impairment of the investment of the net profits interest has occurred since December 31, 2015 when it was written down to its fair value of $31.0 million. Accumulated amortization of the investment in net profits interest was  $23.2 million and  $18.6 million as of December 31, 2019 and 2018, respectively.

Oil prices have declined sharply during the first quarter of 2020 in response to the economic effects of the recent announcement of Saudi Arabia’s abandonment of output restraints and the COVID-19 pandemic. 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, which could materially

52

reduce or completely eliminate the amount of cash available for distribution to Trust unitholders. Absent a significant change in pricing, this decline will result in a triggering event for further testing of impairment in the first quarter of 2020, which could result in an impairment charge up to the remaining balance of the investment in net profits interest.

4.   INCOME FROM NET PROFITS INTEREST

The Trust received income from net profits interest as follows:

	Year Ended December 31,
	2019			2018			2017
Revenues:
Oil sales(1)	$	44,407	(3)	$	51,827	(4)	$	40,931	(5)
Natural gas sales		2,558	(3)		4,296	(4)		3,883	(5)
Total revenues		46,965			56,123			44,814
Costs:
Lease operating expenses		32,555			28,900			30,595
Production taxes		2,328			2,887			2,132
Development costs		1,950			3,309			4,613
Cash settlements on commodity derivatives(2)		-			-			-
Total costs		36,833			35,096			37,340
Net proceeds		10,132			21,027			7,474
Net profits percentage		90	%		90	%		90	%
Income from net profits interest	$	9,119		$	18,924		$	6,727

____________

(1) Oil includes natural gas liquids.

(2) All costless collar hedge contracts terminated as of December 31, 2014, 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, 2019 (consisting of Whiting’s February 2019, May 2019,  August 2019 and November 2019 distributions to the Trust) generally represent crude oil production from October 2018 through September 2019 and natural gas production from September 2018 through August 2019.

(4) Oil and gas sales volumes and related revenues for the year ended December 31, 2018 (consisting of Whiting’s  February 2018,  May 2018,  August 2018 and November 2018 distributions to the Trust) generally represent crude oil production from October 2017 through September 2018 and natural gas production from September 2017 through August 2018.

(5) Oil and gas sales volumes and related revenues for the year ended December 31, 2017  (consisting of Whiting’s  February 2017,  May 2017,  August 2017 and November 2017 distributions to the Trust) generally represent crude oil production from October 2016 through September 2017 and natural gas production from September 2016 through August 2017.

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 $15,120,  $15,119 and $12,828 related to Montana state income taxes for the years ended December 31, 2019,  2018 and 2017, respectively. For Arkansas, Colorado, Michigan, Mississippi, New Mexico, North Dakota and Oklahoma, neither the Trust nor Whiting is withholding the income tax due to 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

53

quarter to any cash reserves established for future expenses of the Trust or adjustments for the recovery of accumulated net losses and accrued interest.

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. 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. There were no accumulated net losses funded or recovered by Whiting during the years ended December 31, 2019, 2018 and 2017.

7.  RELATED PARTY TRANSACTIONS

Plugging and Abandonment — During the years ended December 31, 2019,  2018 and 2017, Whiting incurred $0.9 million,  $1.8 million and $0.7 million, respectively, of plugging and abandonment costs on the underlying properties. Pursuant to the terms of the conveyance agreement, plugging and abandonment costs relating to the underlying properties, net of any proceeds received from the salvage of equipment, are funded entirely by Whiting and are not therefore included as a deduction in the calculation of net proceeds or otherwise deducted from Trust unitholders over the term of the Trust.

Operating Overhead — Pursuant to the terms of its joint operating agreements, Whiting deducts from the gross oil and gas sales proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally, with respect to those underlying properties for which Whiting is the operator but where there is no operating agreement in place, Whiting deducts from the gross proceeds an overhead fee calculated in the same manner that Whiting allocates overhead to other similarly owned properties, which is customary practice in the oil and gas industry.  Operating overhead activities include various engineering, legal, and administrative functions. The fee is adjusted annually pursuant to COPAS guidelines and will increase or decrease each year based on changes in the year‑end index of average weekly earnings of crude petroleum and natural gas workers. The following table presents the Trust’s portion of these overhead charges for the distributions made during the years ended December 31, 2019,  2018 and 2017 (dollars in thousands, except monthly amounts per well):

	Year Ended December 31,
	2019		2018		2017
Total overhead charges (in thousands)	$	1,344	$	1,259	$	1,403
Overhead charge per month per active operated gross well	$	370	$	346	$	372

Administrative Services Fee — Under the terms of the administrative services agreement, the Trust is obligated to pay a quarterly administration fee of $50,000 to Whiting 60 days following the end of each calendar quarter. General and administrative expenses in the Trust’s statements of distributable income for the years ended December 31, 2019,  2018 and 2017 includes  $200,000 in 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 and is billed in arrears. Starting in 2017, such fee escalated by 2.5% each year and therefore, the annual administrative fee paid to the Trustee for 2019 and 2018 services was $188,456 and $183,859, respectively. Accordingly, the escalated quarterly administrative fee of $47,114 was paid by the Trust starting in the second quarter of 2019. General and administrative expenses in the Trust’s statements of distributable income for the years ended December 31, 2019,  2018 and 2017 include $187,307, $182,738 and $178,281, respectively, for administrative fees paid to the Trustee.

Letter of Credit — In June 2012, Whiting established a $1.0 million letter of credit for the Trustee in order to provide a mechanism for the Trustee to pay the operating expenses of the Trust in the event that Whiting should fail to lend funds to the Trust,  if requested to do so by the Trustee.  This letter of credit will not be used to fund NPI distributions to unitholders, and 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, including interest thereon if applicable, have been repaid by the Trust. Such letter of credit is renewed annually during December for a one year term. As of December 31, 2019 and 2018, the Trust had no borrowings under the letter of credit.

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,

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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, 2019 and 2018, the Trust had no borrowings outstanding.

8.  SUBSEQUENT EVENTS

On February 28,  2020, a distribution of $0.014555 per Trust unit was paid to Trust unitholders of record on February 19, 2020. This aggregate distribution to all Trust unitholders consisted of net cash proceeds of $0.5 million paid by Whiting to the Trust, less a provision of $0.2 million for estimated Trust expenses and $3,819 for Montana state income tax withholdings.

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SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS RESERVE INFORMATION (UNAUDITED)

Oil and Gas Reserve Quantities

Estimates of proved reserves attributable to the Trust’s interest in the NPI 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, 2019, all of the underlying properties’ oil and gas reserves are attributable to properties within the United States. Proved reserves attributable to the Trust’s interest in the NPI 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 developed oil and gas reserves attributable to the Trust’s interest in the NPI for the years ended December 31, 2017,  2018 and 2019:

	Oil (MBbl)	Natural Gas (MMcf)	Total (MBOE)
Balance — January 1, 2017(1)(2)	3,257	2,764	3,718
Revisions to previous estimates	147	797	279
Extensions and discoveries	116	131	138
Divestitures	-	-	-
Production	(868)	(1,098)	(1,051)
Balance — December 31, 2017(1)(2)(3)	2,652	2,594	3,084
Revisions to previous estimates	149	459	225
Extensions and discoveries	125	141	149
Divestitures	-	-	-
Production	(842)	(1,085)	(1,023)
Balance — December 31, 2018(1)(2)(3)	2,084	2,109	2,435
Revisions to previous estimates	51	(10)	50
Extensions and discoveries	2	-	2
Divestitures	-	-	-
Production	(806)	(957)	(965)
Balance — December 31, 2019(1)(2)(3)	1,331	1,142	1,522
Proved developed reserves(1)(3):
December 31, 2016	3,257	2,764	3,718
December 31, 2017	2,652	2,594	3,084
December 31, 2018	2,084	2,109	2,435
December 31, 2019	1,331	1,142	1,522

____________

(1) Reserves related to the underlying properties on a 100% full economic life basis as of January 1, 2017,  December 31, 2017,  2018 and 2019 were 7.4 MMBOE,  7.9 MMBOE,  9.2 MMBOE and 9.6 MMBOE, respectively. The oil and gas reserve quantities presented in the tables above are attributable to the 90% NPI based on the NPI termination date, which is currently estimated to be December 31, 2021.

(2) The following table does not include any proved undeveloped reserve quantities as of January 1, 2017, December 31, 2017, 2018 and 2019 primarily because the underlying properties consist of mature producing properties that are generally fully developed. While technical studies have identified an insignificant number of drilling locations that could meet the criteria of proved undeveloped reserves, such locations are not reflected in the reserve reports because no future capital has been committed for the development of such reserves on the underlying properties.

(3) 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 December 31, 2019 reserve report projects that the underlying properties will produce the Trust’s minimum volumes prior to December 31, 2021. Since the net profits interest is not expected to contractually terminate until December 31, 2021, the December 31, 2019 reserve report includes  862 MBOE of additional reserves attributable to the 90% NPI in excess of the Trust’s minimum volumes.

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Notable changes in proved reserves for the year ended December 31, 2019 included:

· Revisions to previous estimates. In 2019, revisions to previous estimates increased proved reserves by a net amount of 50 MBOE. Included in these revisions were (i) 26 MBOE of downward adjustments caused by lower oil and gas pricing incorporated into the Trust’s reserve estimates as of December 31, 2019 compared to December 31, 2018 and (ii) 76 MBOE of net upward adjustments attributable to reservoir analysis.

Notable changes in proved reserves for the year ended December 31, 2018 included:

· Revisions to previous estimates. In 2018, revisions to previous estimates increased proved reserves by a net amount of 225 MBOE. Included in these revisions were (i) 338 MBOE of upward adjustments caused by higher oil and gas pricing incorporated into the Trust’s reserve estimates as of December 31, 2018 compared to December 31, 2017 and (ii) 113 MBOE of net downward adjustments attributable to reservoir analysis.

· Extensions and discoveries. In 2018, total extensions and discoveries of 149 MBOE were attributable to successful drilling in the Keystone South field pursuant to a farm‑out agreement.

Notable changes in proved reserves for the year ended December 31, 2017 included:

· Revisions to previous estimates. In 2017,  revisions to previous estimates increased proved reserves by a net amount of 279 MBOE. Included in these revisions were (i) 418 MBOE of upward adjustments caused by higher oil and gas pricing incorporated into the Trust’s reserve estimates as of December 31, 2017 compared to December 31, 2016 and (ii) 139 MBOE of net downward adjustments attributable to reservoir analysis.

· Extensions and discoveries. In 2017, total extensions and discoveries of 138 MBOE were attributable to successful drilling in the Keystone South field pursuant to a farm‑out agreement.

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’s interest in the NPI is as follows (in thousands):

	December 31,
	2019		2018		2017
Future cash inflows	$	62,656	$	121,469	$	127,724
Future production costs		(29,701)		(65,110)		(85,623)
Future development costs		(3,382)		(4,740)		(8,090)
Future net cash flows		29,573		51,619		34,011
10% annual discount for estimated timing of cash flows		(2,526)		(6,071)		(4,949)
Standardized measure of discounted future net cash flows(1)	$	27,047	$	45,548	$	29,062

____________

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

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

	December 31,
	2019		2018		2017
Beginning of year	$	45,548	$	29,062	$	20,979
Sale of oil and gas produced, net of production costs		(9,791)		(19,926)		(11,503)
Sale of minerals in place		-		-		-
Net changes in prices and production costs		(16,941)		23,272		9,512
Extensions and discoveries less related costs		87		3,051		1,803
Previously estimated development costs incurred during the period		1,288		2,407		1,747
Changes in estimated future development costs		133		177		782
Revisions of previous quantity estimates		2,168		4,599		3,644
Accretion of discount		4,555		2,906		2,098
End of year	$	27,047	$	45,548	$	29,062

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,
	2019		2018		2017
Oil (per Bbl)	$	47.38	$	55.60	$	45.07
Gas (per Mcf)	$	(0.36)	$	2.67	$	3.16

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

	Three Months Ended(1)
	March 31		June 30		September 30		December 31		Total
Year Ended December 31, 2019
Income from net profits interest	$	1,962	$	2,741	$	3,051	$	1,365	$	9,119
Distributable income	$	1,757	$	2,590	$	2,796	$	1,161	$	8,304
Distributions per unit	$	0.095481	$	0.140750	$	0.151980	$	0.063070	$	0.451281
Year Ended December 31, 2018
Income (loss) from net profits interest	$	3,305	$	5,448	$	5,758	$	4,413	$	18,924
Distributable income	$	3,151	$	5,244	$	5,505	$	4,209	$	18,109
Distributions per unit	$	0.171231	$	0.285007	$	0.299197	$	0.228736	$	0.984171

____________

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

******

58

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

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (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. Refer to the risk factors entitled “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, 2019,  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, 2019.

Item 9B. Other Information

None.

59

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.

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, 2019,  the Trustee received administrative fees from the Trust in the amount of $187,307. The Trust does not have any executive officers, directors or employees. Because the Trust does not have a board of directors, it does not have a compensation committee.

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

(a) Security Ownership of Certain Beneficial Owners.

Based on filings with the SEC, the Trustee is not aware of any holders of 5% or more of the units except as set forth below.

Beneficial Owner	Trust Units Beneficially Owned	Percent of Class
Lyda Hunt-Margaret Trust-Al G. Hill, Jr.,  Albert Hill Trust, and 2010 GC Trust(1)	1,305,000	7.1%

____________

(1) Based on a Schedule 13G dated March 3, 2015 filed jointly by the Lyda Hunt-Margaret Trust-Al G. Hill, Jr., the Albert Hill Trust, and the 2010 GC Trust (collectively, the “Reporting Persons”). The principal business office address of each of the Reporting Persons is 47 Highland Park Village, Suite 200, Dallas, Texas 75205. According to the filing, the Lyda Hunt-Margaret Trust-Al G. Hill, Jr. has no sole voting and investment power with respect to units and shared voting and investment power with respect to 735,000 units; the Albert Hill Trust has no sole voting and investment power with respect to units and shared voting and investment power with respect to 470,000 units; and the 2010 GC Trust has no sole voting and investment power with respect to units and shared voting and investment power with respect to 100,000 units. According to the filing, the Reporting Persons collectively beneficially owned 1,305,000 units as of the date of the filing.

(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.

60

Item 13. Certain Relationships, Related Transactions and Director Independence

Letter of Credit

In June 2012, Whiting established a $1.0 million letter of credit for the Trustee in order to provide it with a mechanism to pay the operating expenses of the Trust, in the event that Whiting should fail to lend funds to the Trust,  if requested to do so by the Trustee.  This letter of credit will not be used to fund NPI distributions to unitholders, and 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 the unitholders until all such amounts including interest therein, if applicable, have been repaid by the Trust. Such letter of credit is renewed annually during December for a one year term. As of December 31, 2019 and 2018, the Trust had no borrowings under the letter of credit.

Plugging and Abandonment

During the year ended December 31, 2019, Whiting incurred $0.9 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 its joint operating agreements, Whiting deducts from the gross oil and gas sales proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally, with respect to those underlying properties for which Whiting is the operator but where there is no operating agreement in place, Whiting deducts from the gross proceeds an overhead fee calculated in the same manner that Whiting allocates overhead to other similarly owned properties,  which is customary practice in the oil and gas industry.  Operating overhead activities include various engineering, legal, and administrative functions. For the year ended December 31, 2019, the Trust’s portion of the operating overhead fee totaled $1.3 million and averaged $370 per month per active operated well. The fee is adjusted annually pursuant to COPAS guidelines and will increase or decrease each year based on changes in the year‑end index of average weekly earnings of crude petroleum and natural gas workers.

Administrative Services

Under the terms of the administrative services agreement, the Trust pays a quarterly administration fee of $50,000 to Whiting 60 days following the end of each calendar quarter. General and administrative expenses in the Trust’s statements of distributable income for the year ended December 31, 2019 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 and is billed in arrears. Starting in 2017, such fee escalated by 2.5% each year and therefore, the annual administrative fee paid to the Trustee for 2019 services was $188,456, which was paid in four quarterly installments and billed in arrears. General and administrative expenses in the Trust’s statements of distributable income for the year ended December 31, 2019 include $187,307 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, 2020. During fiscal 2019, Deloitte served as the Trust’s independent registered public accounting firm.

61

The following table presents the aggregate fees billed to the Trust for the fiscal years ended December 31, 2019 and 2018 by Deloitte:

	2019		2018
Audit fees(1)	$	185,000	$	185,000
Audit-related fees		-		-
Tax fees		-		-
All other fees		-		-
Total fees	$	185,000	$	185,000

____________

(1) Fees for audit services in 2019 and 2018 consisted 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.

62

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 7, 2020 [Incorporated by reference to Appendix 1 of this Annual Report on Form 10‑K for the year ended December 31, 2019 filed on March 24, 2020 (File No. 001‑35459)].

____________

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

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 24, 2020

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	7136519944
	www.cgaus.com

February 7,  2020

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

As Trustee of Whiting USA Trust II

601 Travis Street, 16th Floor

Houston, Texas 77002

Re:	Evaluation Summary – SEC Price
	Whiting USA Trust II Underlying Properties
	Total Proved Reserves
	Certain Properties Located in Various States
	As of December 31, 2019
	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 (“Whiting”) to the Whiting USA Trust II. These oil and gas properties are located in Arkansas, Colorado, Michigan, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas and Wyoming, 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 December 31, 2021, which is the estimated termination date for Whiting USA Trust II. This report, completed February 7, 2020, 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
		Developed	Developed	Proved	Total
Net Reserves		Producing	Non-Producing	Developed	Proved
Oil	- Mbbl	7,637.7	410.3	8,048.0	8,048.0
Gas	- MMcf	6,138.1	982.1	7,120.2	7,120.2
NGL	- Mbbl	342.6	57.8	400.5	400.5
Equivalent*	- Mbbl	9,003.4	631.8	9,635.1	9,635.1
Revenue
Oil	- M$	379,043.6	21,142.2	400,185.7	400,185.7
Gas	- M$	(2,389.4)	(482.0)	(2,871.3)	(2,871.3)
NGL	- M$	3,053.0	515.3	3,568.3	3,568.3
Severance Taxes	- M$	20,941.3	960.1	21,901.4	21,901.4
Ad Valorem Taxes	- M$	3,597.2	198.4	3,795.6	3,795.6
Operating Expenses	- M$	187,605.0	7,537.1	195,142.0	195,142.0
Investments	- M$	11,274.7	0.0	11,274.7	11,274.7
Net Operating Income	- M$	156,289.1	12,479.9	168,769.0	168,769.0
Discounted @ 10%	- M$	86,097.2	6,923.5	93,020.9	93,020.9

Underlying Properties Reserves Estimated to be Produced by December 31, 2021
		Proved	Proved
		Developed	Developed	Proved	Total
Net Reserves		Producing	Non-Producing	Developed	Proved
Oil	- Mbbl	1,409.3	0.0	1,409.3	1,409.3
Gas	- MMcf	1,268.7	0.0	1,268.7	1,268.7
NGL	- Mbbl	69.9	0.0	69.9	69.9
Equivalent*	- Mbbl	1,690.7	0.0	1,690.7	1,690.7
Revenue
Oil	- M$	69,457.3	0.0	69,457.3	69,457.3
Gas	- M$	(462.6)	0.0	(462.6)	(462.6)
NGL	- M$	622.6	0.0	622.6	622.6
Severance Taxes	- M$	3,834.1	0.0	3,834.1	3,834.1
Ad Valorem Taxes	- M$	851.5	0.0	851.5	851.5
Operating Expenses	- M$	28,315.9	0.0	28,315.9	28,315.9
Investments	- M$	3,757.1	0.0	3,757.1	3,757.1
Net Operating Income	- M$	32,858.7	0.0	32,858.7	32,858.7
Discounted @ 10%	- M$	30,052.4	0.0	30,052.4	30,052.4

*     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 oil reserves include oil and condensate. Oil volumes and natural gas liquids (NGLs) are expressed in standard 42 gallon barrels and shown herein as thousands of barrels (Mbbl). Gas volumes are expressed in millions of standard cubic feet (MMcf) at standard temperature and pressure bases. The discounted cash flow values shown in the two prior 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 2019, unless prices were otherwise defined by contractual arrangements. Accordingly, West Texas Intermediate oil and Henry Hub gas prices of $55.69 per bbl and $2.58 per MMBtu, respectively, were used as of December 31, 2019. Further adjustments were applied on a lease level basis for oil price differentials, gas price differentials and heating values as furnished by your office and audited by CG&A. 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 $49.72 per  bbl of oil, $8.91 per bbl of natural gas liquids and -$0.40 per mcf of natural gas. For the proved reserves of the underlying properties estimated to be produced by December 31, 2021, the average adjusted prices were $49.28 per bbl of oil, $8.91 per bbl of natural gas liquids and -$0.36 per mcf of natural gas.

Capital, Expenses and Taxes

Capital expenditures, lease operating expenses and ad valorem tax values were forecast as estimated by your office after thorough examination by CG&A. As you explained and CG&A verified, the capital costs were based on the most current estimates, lease operating expenses were based on the analysis of historical actual expenses, and operating overhead is included for 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, NGL 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.

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. Raw production data, lease operating statement data, and ownership interests were also supplied by you and were accepted as furnished. Where possible, CG&A has performed a detailed audit on the data provided, and 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. 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.  

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.

President

Cawley, Gillespie & Associates

Texas Registered Engineering Firm F‑693

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
	Page 1

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

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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.

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

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

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CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS

13640 BRIARWICK DRIVE, 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	7136519944
	www.cgaus.com

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

President of Cawley, Gillespie & Associates

Mr. Brooker has been a Petroleum Consultant for Cawley, Gillespie & Associates (CG&A) since 1992, and became President in 2017. 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) and the Society of Petroleum Evaluation Engineers (SPEE).