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UNITED STATES 

SECURITIES AND EXCHANGE COMMISSION 

Washington, D.C. 20549 

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FORM 10‐Q

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| ﻿ |                                                                                    |
|----------|-----------------------------------------------------------------------------------------|
| ☑ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| ﻿ | For the quarterly period ended September 30, 2018                                  |

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OR

| ﻿ |                                                                                     |
|----------|------------------------------------------------------------------------------------------|
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| ﻿ | For the transition period from _______ to  _______                             |

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Commission File Number: 001-35459

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WHITING USA TRUST II

(Exact name of registrant as specified in its charter) 

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| ﻿                                 |   |                |
|------------------------------------------|--------|---------------------|
| 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)          |

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

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.: 

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| ﻿

						 

						 

						 

						  |     |   |                      |     |
|------------------------------------------------------------------|----------|--------|---------------------------|----------|
| 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 Exchange Act). Yes ☐   No ☑ 

As of November 9, 2018,  18,400,000 Units of Beneficial Interest in Whiting USA Trust II were outstanding. 

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TABLE OF CONTENTS

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| ﻿                                |    |   |
|-----------------------------------------|---------|--------|
| ﻿Glossary of Certain Definitions | 1  |

﻿

﻿

| ﻿                                      |                                                                                                            |     |
|-----------------------------------------------|-----------------------------------------------------------------------------------------------------------------|----------|
| ﻿PART I – FINANCIAL INFORMATION |
| ﻿                                      |                                                                                                            |     |
| ﻿Item 1.                          | Condensed Financial Statements (Unaudited)                                                                      | 5   |
| ﻿                                      | Condensed Statements of Assets, Liabilities and Trust Corpus as of September 30, 2018 and December 31, 2017     | 5   |
| ﻿                                      | Condensed Statements of Distributable Income for the Three and Nine Months Ended September 30, 2018 and 2017    | 5   |
| ﻿                                      | Condensed Statements of Changes in Trust Corpus for the Three and Nine Months Ended September 30, 2018 and 2017 | 5   |
| ﻿                                      | Notes to Condensed Modified Cash Basis Financial Statements                                                     | 6   |
| ﻿Item 2.                          | Trustee’s Discussion and Analysis of Financial Condition and Results of Operations                       | 10  |
| ﻿Item 3.                          | Quantitative and Qualitative Disclosures About Market Risk                                                      | 17  |
| ﻿Item 4.                          | Controls and Procedures                                                                                         | 18  |
| ﻿                                      |                                                                                                            |     |
| ﻿

PART II – OTHER INFORMATION  |
| ﻿                                      |                                                                                                            |     |
| ﻿Item 1A.                         | Risk Factors                                                                                                    | 18  |
| ﻿Item 6.                          | Exhibits                                                                                                        | 18  |

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Table of Contents

			 		

GLOSSARY OF CERTAIN DEFINITIONS 

The following are definitions of significant terms used in this report: 

“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.

“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. 

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

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

﻿

“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.

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

“FASB” Financial Accounting Standards Board. 

﻿

“February 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.

“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. 

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

“Gross proceeds” 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.

“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. 

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“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.

﻿

“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. 

“MBOE” One thousand BOE. 

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

“MMBOE” One million BOE. 

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

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

“Net 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, we make reference to the conveyance agreement, which is filed as an exhibit to this report. Net proceeds is calculated as gross proceeds less Whiting’s share of the following: 

﻿

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

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

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

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

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

|  | · |  | costs paid pursuant 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 

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|--|--------|--|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

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| will be subject to the limitations described within the conveyance agreement (provided that such costs shall not be debited from gross proceeds when actually incurred). |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

﻿

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 payment period, the use of such excess amounts to offset operating expenses may be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period when such amounts, together with other offsets to costs for the applicable quarter, are less than such expenses. If any excess amounts have not been used to offset costs at the time when the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE (10.61 MMBOE at the 90% NPI) have been produced from the underlying properties and sold, which is the time when the NPI will terminate, then unitholders will not be entitled to receive the benefit of such excess amounts.

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, 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.

“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. 

“NGL” Natural gas liquid.

“November 2018 distribution” The cash distribution to Trust unitholders of record on November 19, 2018, which is payable on or before November 29, 2018. 

“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. 

“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. |
|--|----|--|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

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. 

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“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. 

“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. 

“SEC” The United States Securities and Exchange Commission. 

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

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

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PART I – FINANCIAL INFORMATION 

Item 1.  Condensed Financial Statements. 

WHITING USA TRUST II 

Condensed Statements of Assets, Liabilities and Trust Corpus (Unaudited) 

(In thousands, except unit data)

 

| ﻿                                                                                                                               |   |   |   |   |   |   |   |               |         |              |   |         |
|----------------------------------------------------------------------------------------------------------------------------------------|--------|--------|--------|--------|--------|--------|--------|--------------------|--------------|-------------------|--------|--------------|
|                                                                                                                                   |   |   |   |   |   |   |   | September 30, |         | December 31, |
|                                                                                                                                   |   |   |   |   |   |   |   | 2018               |         | 2017              |
| ASSETS                                                                                                                                 |   |   |   |   |   |   |   |               |         |              |   |         |
| Cash and short-term investments                                                                                                        |   |   |   |   |   |   |   | $                  | 272     |              | $      | 377     |
| Investment in net profits interest, net                                                                                                |   |   |   |   |   |   |   |               | 13,575  |              |   | 17,812  |
| Total assets                                                                                                                           |   |   |   |   |   |   |   | $                  | 13,847  |              | $      | 18,189  |
| LIABILITIES AND TRUST CORPUS                                                                                                           |   |   |   |   |   |   |   |               |         |              |   |         |
| Reserve for Trust expenses                                                                                                             |   |   |   |   |   |   |   | $                  | 272     |              | $      | 377     |
| Trust corpus (18,400,000 Trust units issued and outstanding   as of September 30, 2018 and December 31, 2017) |   |   |   |   |   |   |   |               | 13,575  |              |   | 17,812  |
| Total liabilities and Trust corpus                                                                                                     |   |   |   |   |   |   |   | $                  | 13,847  |              | $      | 18,189  |

﻿

Condensed Statements of Distributable Income (Unaudited)

(In thousands, except distributable income per unit data)

﻿

| ﻿                                                 |   |               |           |               |   |           |   |   |           |   |   |           |
|----------------------------------------------------------|--------|--------------------|----------------|--------------------|--------|----------------|--------|--------|----------------|--------|--------|----------------|
| ﻿                                                 |   |               |           |               |   |           |   |   |           |   |   |           |
| ﻿                                                 |   | Three Months Ended |           | Nine Months Ended  |
| ﻿                                                 |   | September 30, |           | September 30, |
| ﻿                                                 |   | 2018               |           | 2017               |   | 2018           |   | 2017   |
| Income from net profits interest                         |   | $                  | 5,758     |               | $      | 1,901     |   | $      | 14,511    |   | $      | 6,311     |
| General and administrative expenses                      |   |               | (157)          |               |   | (196)          |   |   | (705)          |   |   | (589)          |
| Cash reserves used (withheld) for current Trust expenses |   |               | (93)           |               |   | (4)            |   |   | 105       |   |   | (161)          |
| State income tax withholding                             |   |               | (3)            |               |   | (3)            |   |   | (11)           |   |   | (11)           |
| Distributable income                                     |   | $                  | 5,505     |               | $      | 1,698     |   | $      | 13,900    |   | $      | 5,550     |
| Distributable income per unit                            |   | $                  | 0.299197  |               | $      | 0.092270  |   | $      | 0.755435  |   | $      | 0.301645  |

﻿

Condensed Statements of Changes in Trust Corpus (Unaudited)

(In thousands)

﻿

| ﻿                                           |   |               |         |               |   |         |   |   |         |   |   |         |
|----------------------------------------------------|--------|--------------------|--------------|--------------------|--------|--------------|--------|--------|--------------|--------|--------|--------------|
| ﻿                                           |   | Three Months Ended |         | Nine Months Ended  |
| ﻿                                           |   | September 30, |         | September 30, |
| ﻿                                           |   | 2018               |         | 2017               |   | 2018         |   | 2017   |
| Trust corpus, beginning of period                  |   | $                  | 14,927  |               | $      | 20,762  |   | $      | 17,812  |   | $      | 23,929  |
| Distributable income                               |   |               | 5,505   |               |   | 1,698   |   |   | 13,900  |   |   | 5,550   |
| Distributions to unitholders                       |   |               | (5,505)      |               |   | (1,698)      |   |   | (13,900)     |   |   | (5,550)      |
| Amortization of investment in net profits interest |   |               | (1,352)      |               |   | (1,531)      |   |   | (4,237)      |   |   | (4,698)      |
| Trust corpus, end of period                        |   | $                  | 13,575  |               | $      | 19,231  |   | $      | 13,575  |   | $      | 19,231  |

﻿

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

 

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WHITING USA TRUST II 

NOTES TO CONDENSED MODIFIED CASH BASIS FINANCIAL STATEMENTS 

(Unaudited)

 

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 (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, 2017, these oil and gas properties included interests in approximately 1,312 gross (376.7 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. 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. 

As of September 30, 2018, on a cumulative accrual basis, 8.73 MMBOE (82%) 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, 2017.  Accordingly, the Trust’s remaining reserves attributable to the 90% NPI were estimated to be 3.08 MMBOE as of December 31, 2017, which is more than the minimum, but there is no assurance that the Trust will receive more than the minimum amount of reserves. The Trust’s 2017 Annual Report on Form 10-K includes additional information on the Trust’s reserves as of December 31, 2017.  

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2.  BASIS OF ACCOUNTING

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Interim Financial Statements — The accompanying unaudited condensed financial information has been prepared by the Trustee in accordance with the instructions to the Quarterly Report on Form 10-Q. The accompanying financial information is prepared on a comprehensive basis of accounting other than GAAP. In the opinion of the Trustee, the accompanying financial statements include all adjustments (consisting of normal and recurring adjustments) necessary to present fairly, in all material respects, the results of the Trust for the interim periods presented. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The condensed modified cash basis financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with the Trust’s financial statements and related notes included in the Trust’s 2017 Annual Report on Form 10-K.  

﻿

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 (crude oil, natural gas and natural gas liquid sales) less expenses (the amount by which all royalties; lease operating expenses including well workover costs; development costs; production and property taxes; payments made by Whiting to the hedge counterparty upon settlements of hedge contracts; maintenance expenses; producing overhead; and amounts that may be reserved for future development, maintenance or operating expenses, which reserve amounts may not exceed $2.0 million, exceed hedge payments received by Whiting under hedge contracts and other non-production revenue) of the underlying properties multiplied by 90% (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.  

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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: 

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

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

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

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

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

|  | f. |  | The Trust evaluates impairment of the investment in net profits interest by comparing the undiscounted cash flows expected to be realized from the investment in net profits interest to the NPI carrying value. If the expected future undiscounted cash flows are less than the carrying value, the Trust recognizes an impairment loss for the difference between the carrying value and the estimated fair value of the investment in net profits interest. The fair value of the NPI is determined using the expected net discounted future cash flows from the underlying properties that are attributable to the net profits interest. The determination as to 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 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. 

﻿

Recent Accounting Pronouncements — There were no accounting pronouncements issued during the nine months ended September 30, 2018 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. Accumulated amortization of the investment in net profits interest as of September 30, 2018 and December 31, 2017 was $17.4 million and $13.2 million, respectively. 

 

4.  INCOME TAXES

﻿

The Trust is a grantor trust and therefore is not subject to federal income taxes. Accordingly, no recognition is given to federal income taxes in the Trust’s financial statements. The Trust unitholders 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. 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.

﻿

5.  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 

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Trustee no later than 60 days following the end of each quarter (or the next succeeding business day) to the Trust unitholders of record on the 50th day following the end of each quarter. Such amounts equal the excess, if any, of the cash received by the Trust during the quarter, over the expenses of the Trust paid during such quarter, subject to any adjustments for changes made by the Trustee during such quarter to any cash reserves established for future expenses of the Trust or adjustments for the recovery of accumulated net losses and accrued interest.

﻿

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 three and nine months ended September 30, 2018 and 2017.

﻿

6.  RELATED PARTY TRANSACTIONS

﻿

Plugging and Abandonment — During the three and nine months ended September 30, 2018, Whiting incurred $0.1 million and $1.2 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 applicable joint operating agreements, Whiting deducts from the gross oil and gas sales proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally, with respect to those underlying properties for which Whiting is the operator but where there is no operating agreement in place, Whiting deducts from the gross proceeds an overhead fee calculated in the same manner that Whiting allocates overhead to other similarly owned properties, which is customary practice in the oil and gas industry. Operating overhead activities include various engineering, legal, and administrative functions. The fee is adjusted annually pursuant to COPAS guidelines and will increase or decrease each year based on changes in the year-end index of average weekly earnings of crude petroleum and natural gas workers. The following table presents the Trust’s portion of these overhead charges for the distributions made during the three and nine months ended September 30, 2018 and 2017 (dollars in thousands, except monthly amounts per well): 

| ﻿                                           |   |               |      |               |   |      |   |   |      |   |   |        |
|----------------------------------------------------|--------|--------------------|-----------|--------------------|--------|-----------|--------|--------|-----------|--------|--------|-------------|
| ﻿                                           |   |               |      |               |   |      |   |   |      |   |   |        |
| ﻿                                           |   | Three Months Ended |      | Nine Months Ended  |
| ﻿                                           |   | September 30, |      | September 30, |
| ﻿                                           |   | 2018               |      | 2017               |   | 2018      |   | 2017   |
| Total overhead charges (in thousands)              |   | $                  | 338  |               | $      | 363  |   | $      | 999  |   | $      | 1,055  |
| Overhead charge per month per active operated well |   | $                  | 359  |               | $      | 381  |   | $      | 354  |   | $      | 369    |

﻿

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 condensed statements of distributable income for the three and nine months ended September 30, 2018 include $50,000 and $150,000, respectively, for quarterly administrative fees paid to Whiting. General and administrative expenses in the Trust’s condensed statements of distributable income for the three and nine months ended September 30, 2017 also include $50,000 and $150,000, respectively, for quarterly administrative fees paid to Whiting. 

﻿

Trustee Administrative Fee — Under the terms of the Trust agreement, the Trust pays an annual administrative fee to the Trustee of $175,000, which is paid in four quarterly installments and is billed in arrears. Starting in 2017, such fee escalates by 2.5% each year and therefore, the annual administrative fee to be paid to the Trustee for 2018 and 2017 services is $183,859 and $179,375, respectively. Accordingly, the escalated quarterly administrative fee of $45,965 was paid by the Trust starting in the second quarter of 2018. General and administrative expenses in the Trust’s condensed statements of distributable income for the three and nine months ended September 30, 2018 include $45,965 and $136,773, respectively, for quarterly administrative fees paid to the Trustee. General and administrative expenses in the Trust’s condensed statements of distributable income for the three and nine months ended September 30, 2017 include $44,844 and $133,438, respectively, for quarterly 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 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 

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credit or were to borrow funds from Whiting or other entities, no further distributions would be made to unitholders until all such amounts, including interest thereon if applicable, have been repaid by the Trust.

Lending to the Trust  — The Trustee can authorize the Trust to borrow money for the purpose of paying Trust administrative or incidental expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee, Whiting or the Delaware Trustee, as a lender, provided that the terms of the loan are similar to the terms it would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself, which may be a non-interest bearing account, and make other short-term investments with the funds distributed to the Trust. As of September 30, 2018 and December 31, 2017, the Trust had no borrowings outstanding. 

﻿

7.  SUBSEQUENT EVENT

﻿

On November 8, 2018, the Trustee announced the Trust’s distribution of net profits for the third quarterly payment period in 2018. Unitholders of record on November 19, 2018 are expected to receive a distribution of $0.228736 per Trust unit, which is payable on or before November 29, 2018. This aggregate distribution to all Trust unitholders is expected to consist of net cash proceeds of $4.4 million paid by Whiting to the Trust, less a provision of $0.2 million for estimated Trust expenses and $4,240 for Montana state income tax withholdings.

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Item 2.  Trustee’s Discussion and Analysis of Financial Condition and Results of Operations 

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 100%-owned subsidiary of Whiting Petroleum Corporation. 

The following review of the Trust’s financial condition and results of operations should be read in conjunction with the financial statements and notes thereto, as well as the Trustee’s discussion and analysis contained in the Trust’s 2017 Annual Report on Form 10‐K. The Trust’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports are available on the SEC’s website www.sec.gov.  

Note Regarding Forward-Looking Statements 

﻿

This Quarterly Report on Form 10-Q 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 Quarterly Report on Form 10-Q, 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 Quarterly Report on Form 10-Q, could affect the future results of the energy industry in general, and Whiting and the Trust in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements: 

﻿

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

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

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

|  | · |  | future production and development costs, 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 the Trust’s 2017 Annual Report on Form 10-K. |
|--|--------|--|-----------------------------------------------------------------------------------------------------------------------------|

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 these factors. The Trustee assumes no obligation, and disclaims any duty, to update these forward-looking 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 September 30, 2018. The August 2018 distribution was mainly affected by April 2018 through June 2018 oil prices and March 2018 through May 2018 natural gas prices. 

﻿

| ﻿    |   |        |   |   |        |   |   |        |   |   |        |   |   |        |   |   |        |   |   |        |   |   |        |   |   |        |   |   |        |   |   |        |
|-------------|--------|-------------|--------|--------|-------------|--------|--------|-------------|--------|--------|-------------|--------|--------|-------------|--------|--------|-------------|--------|--------|-------------|--------|--------|-------------|--------|--------|-------------|--------|--------|-------------|--------|--------|-------------|
| ﻿    |   |        |   |   |        |   |   |        |   |   |        |   |   |        |   |   |        |   |   |        |   |   |        |   |   |        |   |   |        |   |   |        |
| ﻿    | 2016   |        | 2017   |   | 2018        |
| ﻿    | Q1     |        | Q2     |   | Q3          |   | Q4     |        | Q1     |   | Q2          |   | Q3     |        | Q4     |   | Q1          |   | Q2     |        | Q3     |
| Crude oil   | $      | 33.51  |   | $      | 45.60  |   | $      | 44.94  |   | $      | 49.33  |   | $      | 51.86  |   | $      | 48.29  |   | $      | 48.19  |   | $      | 55.39  |   | $      | 62.89  |   | $      | 67.90  |   | $      | 69.50  |
| Natural gas | $      | 2.06   |   | $      | 1.98   |   | $      | 2.93   |   | $      | 2.98   |   | $      | 3.07   |   | $      | 3.09   |   | $      | 2.89   |   | $      | 2.87   |   | $      | 3.13   |   | $      | 2.77   |   | $      | 2.88   |

Lower 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 and (ii) a reduction in the amount of oil, natural gas and natural gas liquids that is 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). All 

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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.

﻿

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 2017 reserve report or (b) the sale of the net profits interest. After the termination of the Trust, it will pay no further distributions. The Trust is required to sell the NPI and liquidate if cash proceeds to the Trust from the net profits interest are less than $2.0 million for each of any two consecutive years.

﻿

Since the assets of the Trust are depleting assets, a portion of each cash distribution paid, if any, on the Trust units is to be considered by investors as a return of capital, with the remainder being considered as a return on investment or yield. As a result, the market price of the Trust units will decline to zero at the termination of the Trust. As of September 30, 2018 on a cumulative accrual basis, 8.73 MMBOE (82%) of the 10.61 MMBOE attributable to the NPI have been produced and sold or divested (of which 257 MBOE, which is 90% of 286 MBOE, are included as gross proceeds in the Trust’s November 2018 distribution). 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, 2017. Accordingly, the Trust’s remaining reserves attributable to the 90% NPI were estimated to be 3.08 MMBOE as of December 31, 2017, which is more than the minimum, but there is no assurance that the Trust will receive more than the minimum amount of reserves. The Trust’s 2017 Annual Report on Form 10-K includes additional information on the Trust’s reserves, including the underlying assumptions, as of December 31, 2017.

﻿

Capital Expenditure Activities 

﻿

The primary goal of the planned capital expenditures relative to the underlying properties is to mitigate a portion of the natural decline in production from producing properties. The underlying properties have a capital expenditure budget per the December 31, 2017 reserve report of $9.0 million estimated to be spent between January 1, 2018 and December 31, 2021, the estimated termination date of the NPI. 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. In addition, no assurance can be given that Whiting’s actual level of capital expenditures on the underlying properties will meet this $9.0 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. Please read the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, Item 1A. Risk Factors “Whiting has limited control over activities on the underlying properties that Whiting does not operate, which could reduce production from the underlying properties, increase capital expenditures and reduce cash available for distribution to Trust unitholders.” The following table presents the underlying properties’ aggregate capital expenditures attributable to the February 2018, May 2018 and August 2018 distributions (in thousands): 

﻿

﻿

| ﻿        |         |        |
|-----------------|--------------|-------------|
| ﻿        |         |        |
| ﻿        | 2018         |
| ﻿        | Capital      |
| Region          | Expenditures |
| Rocky Mountains | $            | 1,517  |
| Permian Basin   |         | 371    |
| Gulf Coast      |         | 30     |
| Mid-Continent   |         | 27     |
| Total           | $            | 1,945  |

﻿

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 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. 

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Therefore, the capital expenditures included in the net proceeds attributable to the underlying properties cannot exceed $4.0 million during the year ending December 31, 2018.

﻿

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 (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, and a fourth well was drilled and completed during the second quarter of 2018, 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 second quarter of 2019 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. No drilling operations have occurred under the Signal Peak farm-out, and if no such drilling has commenced on or before March 31, 2019 the agreement will terminate.

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Results of Trust Operations 

﻿

Comparison of Results of the Trust for the Nine Months Ended September 30, 2018 and 2017

﻿

The following is a summary of income from net profits interest and distributable income received by the Trust for the nine months ended September 30, 2018 and 2017 (dollars in thousands, except per Bbl, per Mcf and per BOE amounts):

﻿

| ﻿                                        |   |               |            |   |   |   |          |   |
|-------------------------------------------------|--------|--------------------|-----------------|--------|--------|--------|---------------|--------|
| ﻿                                        |   |               |            |   |   |   |          |   |
| ﻿                                        |   | Nine Months Ended  |
| ﻿                                        |   | September 30, |
| ﻿                                        |   | 2018               |            | 2017   |
| Sales volumes:                                  |   |               |            |   |   |   |          |   |
| Oil from underlying properties (Bbl)(1)         |   |               | 720,168    | (3)    |   |   | 717,147  | (4)    |
| Natural gas from underlying properties (Mcf)    |   |               | 1,001,623  | (3)    |   |   | 923,539  | (4)    |
| Total production (BOE)                          |   |               | 887,106    |   |   |   | 871,071  |   |
| Average sales prices:                           |   |               |            |   |   |   |          |   |
| Oil (per Bbl)(1)                                |   | $                  | 53.53      |   |   | $      | 42.53    |   |
| Natural gas (per Mcf)(2)                        |   | $                  | 3.27       |   |   | $      | 3.15     |   |
| Cost metrics:                                   |   |               |            |   |   |   |          |   |
| Lease operating expenses (per BOE)              |   | $                  | 24.32      |   |   | $      | 25.94    |   |
| Production tax rate (percent of total revenues) |   |               | 5.2        | %      |   |   | 4.5      | %      |
| Revenues:                                       |   |               |            |   |   |   |          |   |
| Oil sales(1)                                    |   | $                  | 38,551     | (3)    |   | $      | 30,501   | (4)    |
| Natural gas sales                               |   |               | 3,270      | (3)    |   |   | 2,909    | (4)    |
| Total revenues                                  |   |               | 41,821     |   |   |   | 33,410   |   |
| Costs:                                          |   |               |            |   |   |   |          |   |
| Lease operating expenses                        |   |               | 21,574     |   |   |   | 22,597   |   |
| Production taxes                                |   |               | 2,179      |   |   |   | 1,504    |   |
| Development costs                               |   |               | 1,945      |   |   |   | 2,297    |   |
| Total costs                                     |   |               | 25,698     |   |   |   | 26,398   |   |
| Net proceeds                                    |   |               | 16,123     |   |   |   | 7,012    |   |
| Net profits percentage                          |   |               | 90         | %      |   |   | 90       | %      |
| Income from net profits interest                |   |               | 14,511     |   |   |   | 6,311    |   |
| Provision for estimated Trust expenses          |   |               | (600)           |   |   |   | (750)         |   |
| Montana state income tax withheld               |   |               | (11)            |   |   |   | (11)          |   |
| Distributable income                            |   | $                  | 13,900     |   |   | $      | 5,550    |   |

____________

|  | (1) |  | Oil includes natural gas liquids. |
|--|-----|--|-----------------------------------|

|  | (2) |  | The average sales price of natural gas for the gas production months within the nine months ended September 30, 2018 and 2017 exceeded the average NYMEX gas prices for those same months within the respective periods due to the “liquids-rich” content of a portion of the natural gas volumes produced by the underlying properties. |
|--|-----|--|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

|  | (3) |  | Oil and gas sales volumes and related revenues for the nine months ended September 30, 2018 (consisting of Whiting’s February 2018, May 2018 and August 2018 distributions to the Trust) generally represent crude oil production from October 2017 through June 2018 and natural gas production from September 2017 through May 2018.   |
|--|-----|--|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

|  | (4) |  | Oil and gas sales volumes and related revenues for the nine months ended September 30, 2017 (consisting of Whiting’s February 2017, May 2017 and August 2017 distributions to the Trust) generally represent crude oil production from October 2016 through June 2017 and natural gas production from September 2016 through May 2017. |
|--|-----|--|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

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: 

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Revenues. Oil and natural gas revenues increased $8.4 million (or 25%) during the nine months ended September 30, 2018 as compared to the same 2017 period. Sales revenue is a function of average commodity prices realized and oil and gas volumes sold. The increase in revenue between periods was due to higher realized oil and natural gas prices as well as a slight increase in oil and natural gas production volumes. The average sales price realized for crude oil and natural gas increased by 26% and 4%, respectively, between periods primarily as a result of higher NYMEX oil prices and improved natural gas differentials, which were partially offset by rising oil differentials during the nine months ended September 30, 2018.  Crude oil production volumes remained stable and natural gas volumes increased by 78 MMcf (or 8%), when comparing the first nine months of 2018 to the same period in 2017. Oil volumes during the nine months ended September 30, 2018 remained consistent with the same 2017 period primarily due to three new wells that came online as a result of the Keystone South farm-out agreement,  which increases were almost fully offset by normal field production decline.  The higher gas volumes between periods were primarily due to (i) the new Keystone South farm-out wells and (ii) gas production from 14 wells in the Keystone South field, which production was flared during a portion of 2017 as a result of a gas plant in Texas being shutdown. These gas volume increases between periods were partially offset, however, by gas from one unit in the Lake Como field being flared instead of produced as the result of a gas plant in Mississippi being shutdown for a portion of the first nine months of 2018,  as well as two wells that were shut-in during portions of the first nine months of 2018. Based on the December 31, 2017 reserve report, overall production attributable to the underlying properties is expected to decline at an average annual rate of approximately 13.3% for oil and 25.9% for gas from 2018 through the estimated December 31, 2021 NPI termination date.

Lease Operating Expenses. Lease operating expenses decreased by $1.0 million (or 5%) during the first nine months of 2018 compared to the same 2017 period primarily due to (i)  a $0.4 million decrease in oilfield goods and services, (ii) a  $0.3 million decline in ad valorem taxes and (iii) lower operating costs on Whiting-operated properties of $0.3 million. LOE on a per BOE basis decreased 6% from $25.94 during the nine months ended September 30, 2017 to $24.32 for the same period in 2018 mainly due to lower overall LOE and the slight increase in oil and natural gas production volumes between periods.

Production Taxes. Production taxes are typically calculated as a percentage of oil and gas revenues. Production taxes as a percentage of revenues increased from 4.5% during the first nine months of 2017 to 5.2% for the same period in 2018. Additionally, overall production taxes for the first nine months of 2018 increased $0.7 million (or 45%) as compared to the same 2017 period. These increases are primarily due to (i) higher oil and natural gas revenues between periods and (ii) certain wells within the Torchlight field in Wyoming being granted a “stripper well” production tax exemption during 2017, which reduced the tax rate for production volumes from these wells and resulted in a tax refund of $0.2 million related to prior periods.

Development Costs. Development costs for the nine months ended September 30, 2018 were $0.4 million (or 15%) lower as compared to the same 2017 period. Development costs between periods were impacted by a $0.7 million decrease relating to timing differences associated with invoices received and paid between periods for non-operated properties in the Sand Tank field and reduced drilling and capital workover costs of $0.4 million between periods in the Garland and Flying W fields, which declines were partially offset by increased drilling and capital workover activity in the Keystone South, Rangely, West Dickinson and Cedar Hills fields of $0.7 million during the first nine months of 2018.  

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Comparison of Results of the Trust for the Three Months Ended September 30, 2018 and 2017

The following is a summary of income from net profits interest and distributable income received by the Trust for the three months ended September 30, 2018 and 2017 (dollars in thousands, except per Bbl, per Mcf and per BOE amounts): 

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| ﻿                                        |   |               |          |   |   |   |          |   |
|-------------------------------------------------|--------|--------------------|---------------|--------|--------|--------|---------------|--------|
| ﻿                                        |   |               |          |   |   |   |          |   |
| ﻿                                        |   | Three Months Ended |
| ﻿                                        |   | September 30, |
| ﻿                                        |   | 2018               |          | 2017   |
| Sales volumes:                                  |   |               |          |   |   |   |          |   |
| Oil from underlying properties (Bbl)(1)         |   |               | 231,446  | (3)    |   |   | 238,914  | (4)    |
| Natural gas from underlying properties (Mcf)    |   |               | 310,198  | (3)    |   |   | 269,627  | (4)    |
| Total production (BOE)                          |   |               | 283,146  |   |   |   | 283,852  |   |
| Average sales prices:                           |   |               |          |   |   |   |          |   |
| Oil (per Bbl)(1)                                |   | $                  | 57.80    |   |   | $      | 42.78    |   |
| Natural gas (per Mcf)(2)                        |   | $                  | 2.95     |   |   | $      | 2.98     |   |
| Cost metrics:                                   |   |               |          |   |   |   |          |   |
| Lease operating expenses (per BOE)              |   | $                  | 23.24    |   |   | $      | 27.07    |   |
| Production tax rate (percent of total revenues) |   |               | 5.0      | %      |   |   | 2.9      | %      |
| Revenues:                                       |   |               |          |   |   |   |          |   |
| Oil sales(1)                                    |   | $                  | 13,378   | (3)    |   | $      | 10,221   | (4)    |
| Natural gas sales                               |   |               | 914      | (3)    |   |   | 803      | (4)    |
| Total revenues                                  |   |               | 14,292   |   |   |   | 11,024   |   |
| Costs:                                          |   |               |          |   |   |   |          |   |
| Lease operating expenses                        |   |               | 6,580    |   |   |   | 7,684    |   |
| Production taxes                                |   |               | 717      |   |   |   | 320      |   |
| Development costs                               |   |               | 597      |   |   |   | 908      |   |
| Total costs                                     |   |               | 7,894    |   |   |   | 8,912    |   |
| Net proceeds                                    |   |               | 6,398    |   |   |   | 2,112    |   |
| Net profits percentage                          |   |               | 90       | %      |   |   | 90       | %      |
| Income from net profits interest                |   |               | 5,758    |   |   |   | 1,901    |   |
| Provision for estimated Trust expenses          |   |               | (250)         |   |   |   | (200)         |   |
| Montana state income tax withheld               |   |               | (3)           |   |   |   | (3)           |   |
| Distributable income                            |   | $                  | 5,505    |   |   | $      | 1,698    |   |

____________

|  | (1) |  | Oil includes natural gas liquids. |
|--|-----|--|-----------------------------------|

|  | (2) |  | The average sales price of natural gas for the gas production months within the three months ended September 30, 2018 and 2017 exceeded the average NYMEX gas prices for those same months within the respective periods due to the “liquids-rich” content of a portion of the natural gas volumes produced by the underlying properties. |
|--|-----|--|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

|  | (3) |  | Oil and gas sales volumes and related revenues for the three months ended September 30, 2018 (consisting of Whiting’s August 2018 distribution to the Trust) generally represent crude oil production from April 2018 through June 2018 and natural gas production from March 2018 through May 2018.   |
|--|-----|--|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

|  | (4) |  | Oil and gas sales volumes and related revenues for the three months ended September 30, 2017 (consisting of Whiting’s August 2017 distribution to the Trust) generally represent crude oil production from April 2017 through June 2017  and natural gas production from March 2017 through May 2017. |
|--|-----|--|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

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 increased $3.3 million (or 30%) during the three months ended September 30, 2018 as compared to the same 2017 period. Sales revenue is a function of average commodity prices realized and oil and gas volumes sold. The increase in revenue between periods was primarily due to higher realized oil prices and a slight increase in natural gas production volumes. The average sales price realized for crude oil increased by 35% between periods as a result of higher NYMEX 

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oil prices, which were partially offset by rising oil differentials during the third quarter of 2018. The average sales price realized for natural gas, however, decreased by 1%  during the three months ended September 30, 2018 compared to the same 2017 period due to a decline in NYMEX natural gas prices, which decline was almost fully offset by improved gas differentials between periods.  Crude oil production volumes decreased by 7 MBbl (or 3%) between periods and natural gas production volumes increased by 41 MMcf (or 15%) during the third quarter of 2018 compared to the same period in 2017. The oil volume decrease between periods was primarily related to normal field production decline and differences in timing associated with revenues received from non-operated properties, which were partially offset by three new wells that came online as a result of the Keystone South farm-out agreement. The higher gas volumes between periods were primarily due to (i) the new Keystone South farm-out wells,  (ii) gas production from 14 wells in the Keystone South field, which production was flared during a portion of 2017 as a result of a gas plant in Texas being shutdown and (iii) one well that was shut-in for a workover during a portion of the 2017 period. These gas volume increases were partially offset, however, by normal field production decline and one well that was shut-in during the third quarter of 2018. Based on the December 31, 2017 reserve report, overall production attributable to the underlying properties is expected to decline at an average annual rate of approximately 13.3% for oil and 25.9% for gas from 2018 through the estimated December 31, 2021 NPI termination date.

Lease Operating Expenses. Lease operating expenses decreased $1.1 million (or 14%) during the third quarter of 2018 compared to the same 2017 period primarily due to (i) a  $0.7 million decrease in oilfield goods and services, (ii)  a $0.2 million decline in ad valorem taxes and (iii) lower operating costs on Whiting-operated properties of $0.2 million. LOE on a per BOE basis decreased by 14% from $27.07 during the three months ended September  30, 2017 to $23.24 for the same period in 2018 mainly due to lower overall LOE between periods.

Production Taxes. Production taxes are typically calculated as a percentage of oil and gas revenues. Production taxes as a percentage of revenues increased from 2.9% for the three months ended September 30, 2017 to 5.0% for the same period in 2018. Additionally, overall production taxes for the third quarter of 2018 increased $0.4 million (or 124%) as compared to the same 2017 period. These increases are primarily due to (i) higher oil and natural gas revenues between periods and (ii) certain wells within the Torchlight field in Wyoming being granted a “stripper well” production tax exemption during 2017, which reduced the tax rate for production volumes from these wells and resulted in a tax refund of $0.2 million in the third quarter of 2017.

Development Costs. Development costs for the three months ended September 30, 2018 were $0.3 million (or 34%) lower as compared to the same 2017 period. This decrease was primarily related to reduced drilling and capital workover costs of $0.4 million between periods in the Garland, Flying W and Rangely fields, which decrease was partially offset by increased drilling and capital workover activity in the West Dickinson field of $0.1 million during the third quarter of 2018. 

﻿

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), 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 October 31, 2018, the Trust had cash reserves of $0.2 million and a provision for estimated Trust expenses of $0.2 million from the November 2018 distribution 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.

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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 have been repaid by the Trust.

Reserve for Expenditures.  Whiting may reserve from the gross proceeds amounts up to a total of $2.0 million at any time for future development, maintenance or operating expenses. However, Whiting has not funded such a reserve since the inception of the Trust, including during the three and nine months ended September 30, 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 three and nine months ended September 30, 2018, Whiting incurred $0.1 million and $1.2 million, respectively, of plugging and abandonment costs on the underlying properties that were not charged to the unitholders of the Trust. 

Future Trust Payment Periods 

﻿

On November 8, 2018, the Trustee announced the Trust’s distribution of net profits for the third quarterly payment period in 2018. Unitholders of record on November 19, 2018 are expected to receive a distribution of $0.228736 per Trust unit, which is payable on or before November 29, 2018. This aggregate distribution to all Trust unitholders is expected to consist of net cash proceeds of $4.4 million paid by Whiting to the Trust, less a provision of $0.2 million for estimated Trust expenses and $4,240 for Montana state income tax withholdings.

﻿

Although oil and gas prices have stabilized since the lows experienced during the 2016 distribution periods, oil and gas prices historically have been volatile and may fluctuate widely in the future. The Trust is unable to predict future commodity prices; however, if prices decline in future periods, a reduction in the amount of net proceeds to which the Trust is entitled is likely to occur. 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. If the NPI generates net losses or limited net proceeds, the net profits interest may not provide sufficient funds to the Trustee to enable it to pay all of the Trust’s administrative expenses. 

﻿

New Accounting Pronouncements 

There were no accounting pronouncements issued during the nine months ended September 30, 2018 applicable to the Trust or its financial statements. 

Critical Accounting Policies and Estimates 

A disclosure of critical accounting policies and the more significant judgments and estimates used in the preparation of the Trust’s financial statements is included in Item 7 of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2017. There have been no significant changes to the critical accounting policies during the nine months ended September 30, 2018.

﻿

Item 3.  Quantitative and Qualitative Disclosures About Market Risk 

Commodity Hedge Contracts 

﻿

The primary asset of 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 Whiting can economically produce. Whiting sells the oil, natural gas and natural gas liquid production from the underlying properties under floating market price contracts each month. Whiting entered into certain hedge contracts, 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 

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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. 

Item 4.  Controls and Procedures 

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

As of the end of the period covered by this report, the Trustee carried out an evaluation of the 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. For a description of certain risks relating to these arrangements and risks relating to the Trustee’s reliance on information reported by Whiting and included in the Trust’s results of operations, refer to the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, Item 1A. Risk Factors “The Trust and the Trust unitholders have no voting or managerial rights with respect to the underlying properties. As a result, neither the Trust nor the Trust unitholders have any ability to influence the operation of the underlying properties.” 

Changes in Internal Control over Financial Reporting. During the quarter ended September 30, 2018, 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.

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PART II – OTHER INFORMATION 

Item 1A.  Risk Factors 

Risk factors relating to the Trust are contained in Item 1A of the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017. No material change to such risk factors has occurred during the nine months ended September 30, 2018.

Item 6.  Exhibits 

The exhibits listed in the accompanying exhibit index are filed as part of this Quarterly Report on Form 10-Q.

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EXHIBIT INDEX 

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| ﻿            |   |                                                                                                                                                                                                                                                                                                                                                                                   |
|---------------------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Exhibit Number |   |  

Exhibit 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.                                                                                                                                                                                                                                                                                                               |
| *                   |   | Asterisk indicates exhibit previously filed with the SEC and incorporated herein by reference.                                                                                                                                                                                                                                                                                         |

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SIGNATURES 

﻿

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, 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                                                                      |
| ﻿                             |   |                                                                                     |

 November 9, 2018 

﻿

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

﻿

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