Item 1. Business
General
Whiting USA Trust II (the “Trust”) is a statutory trust formed on December 5, 2011 under the Delaware Statutory Trust Act, pursuant to a trust agreement (the “Trust agreement”) among Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and Wilmington Trust, National Association, as Delaware Trustee (the “Delaware Trustee”). The initial capitalization of the Trust estate was funded by Whiting Petroleum Corporation (“Whiting”) on December 8, 2011. The Trust maintains its offices at the office of the Trustee, at 601 Travis Street, 16th Floor, Houston, Texas 77002. The telephone number of the Trustee is 512-236-6599.
The Trust makes copies of its reports under the Exchange Act available at http://whitingwhz.investorhq.businesswire.com. The Trust’s filings under the Exchange Act are also available electronically from the website maintained by the SEC at http://www.sec.gov. In addition, the Trust will provide electronic and paper copies of its recent filings free of charge upon request to the Trustee.
As of December 31, 2011, the Trust had no assets other than a de minimis cash balance from its initial capitalization and had conducted no operations other than organizational activities. In March 2012, the Trust issued 18,400,000 units of beneficial interest in the Trust (“Trust units”) to Whiting in exchange for the conveyance of the NPI by Whiting Oil and Gas. The NPI represents the right for the Trust to receive 90% of the net proceeds from Whiting’s interests in certain existing oil, natural gas and natural gas liquid producing properties which are referred to as “the underlying properties”. The underlying properties are located in the Permian Basin, Rocky Mountains, Gulf Coast and Mid-Continent regions of the United States. The underlying properties include interests in 1,312 gross (376.7 net) producing oil and gas wells as of December 31, 2017. Whiting completed an initial public offering of Trust units selling all of its 18,400,000 units on March 28, 2012. The Trust units are currently traded on the OTC, operated by OTC Markets Group, under the trading symbol “WHZT”, but the Trust can provide no assurance that any trading market for the Trust units will exist on the OTC in the future or that current trading levels will be sustained or will not diminish.
The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), or (b) the sale of the net profits interest. The Trust is required to sell the NPI and liquidate if cash proceeds to the Trust from the net profits interest are less than $2.0 million for each of any two consecutive years. During the years ended December 31, 2017 and 2016, the Trust received cash proceeds of $6.7 million and $1.9 million, respectively, from the net profits interest. After the termination of the Trust, it will pay no further distributions.
As of December 31, 2017, on a cumulative accrual basis 7.95 MMBOE (75%) of the 10.61 MMBOE attributable to the NPI have been produced and sold or divested. Further detail on the reserves is provided herein under the section titled “Properties-Description of the Underlying Properties-Reserves”, and such reserve information is based upon a reserve report prepared by independent reserve engineers Cawley, Gillespie & Associates, Inc. for the underlying properties as of December 31, 2017, which is referred to as the “reserve report.” According to the reserve report, the portion of the 11.79 MMBOE (10.61 MMBOE at the 90% NPI) reserve quantities attributable to the NPI not yet produced and sold or divested as of December 31, 2017 is projected to be produced from the underlying properties prior to December 31, 2021, which reserve report is based on NYMEX oil and gas prices of $51.34 per Bbl and $2.98 per MMBtu, respectively, pursuant to current SEC and FASB guidelines and the other assumptions included therein. The average NYMEX oil and gas prices for the month of January 2018 were $63.66 per Bbl and $3.58 per MMBtu, respectively. Refer to “Risk Factors” in Item 1A
Item 1A. Risk Factors
The amounts of cash distributions by the Trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquids prices.
The reserves attributable to the underlying properties and the quarterly cash distributions of the Trust are highly dependent upon the prices realized from the sale of oil, natural gas and natural gas liquids. Prices of oil, natural gas and natural gas liquids applicable to the underlying properties can fluctuate widely on a quarter-to-quarter basis in response to a variety of factors that are beyond the control of the Trust and Whiting, including, but not limited to, the following:
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changes in regional, domestic and global supply and demand for oil and natural gas;
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the level of global oil and natural gas inventories;
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the actions of the Organization of Petroleum Exporting Countries;
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the price and quantity of imports of foreign oil and natural gas;
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political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity, such as recent conflicts in the Middle East;
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the level of global oil and natural gas exploration and production activity;
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the effects of global credit, financial and economic issues;
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developments of United States energy infrastructure;
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weather conditions;
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technological advances affecting energy consumption;
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current and anticipated changes to domestic and foreign governmental regulations, including those that may arise in response to the policies of the Trump Administration;
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proximity and capacity of oil and natural gas pipelines and other transportation facilities;
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the price and availability of competitors’ supplies of oil and gas in captive market areas;
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the price and availability of alternative fuels; and
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acts of force majeure.
Moreover, government regulations, such as regulation of oil and natural gas gathering and transportation, can adversely affect commodity prices in the long term.
These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements. Also, prices for crude oil and prices for natural gas do not necessarily move in tandem. Declines in oil or natural gas prices would not only reduce revenue, but could also reduce the amount of oil and natural gas that can be economically produced from the underlying properties.
Whiting entered into hedge contracts, which were structured as costless collar arrangements and were conveyed to the Trust to reduce the exposure to volatility in the underlying properties’ oil and gas revenues due to fluctuations in crude oil and natural gas prices, and to achieve more predictable cash flows. However, all such costless collar hedge contracts terminated as of December 31, 2014 (which hedging effects extended through the February 2015 distribution to unitholders), and no additional hedges are allowed to be placed on the Trust assets. As a result, the amounts of the cash distributions may fluctuate significantly as a result of changes in commodity prices because there are no hedge contracts in place to reduce the Trust’s exposure to oil and natural gas price volatility.
Substantial and extended declines in oil, natural gas and natural gas liquids prices have resulted and may continue to result in reduced net proceeds to which the Trust is entitled and may ultimately reduce the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties. As a result, the operator of any of the underlying properties could determine during periods of low commodity prices to shut in or curtail production from the underlying properties. In addition, the operator of these properties could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Because these properties are mature, decreases in commodity prices could have a more significant effect on the economic viability of these properties as compared to more recently discovered properties. The commodity price sensitivity of these mature wells is due to a culmination of factors that vary from well to well, including the additional costs associated with water handling and disposal, chemicals, surface equipment maintenance, downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result, the volatility of commodity prices may cause the amount of future cash distributions to Trust unitholders to fluctuate, and a substantial decline in the price, or sustained periods of low prices, of oil, natural gas or natural gas liquids, will likely materially reduce, or completely eliminate, the amount of cash available for distribution to Trust unitholders.
			
		
			
		
The Trust units have been delisted from the New York Stock Exchange. It will likely be more difficult for unit holders to sell the Trust units or to obtain accurate quotations of the Trust units.
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The Trust units ceased trading on the NYSE on January 6, 2016. The Trust units transitioned to OTC, operated by OTC Markets Group, effective with the opening of trading on January 7, 2016 under the trading symbol “WHZT.” The Trust can provide no assurance that any trading market for the Trust units will exist on OTC or that current trading levels will be sustained or not diminish. Securities traded on the over-the-counter markets are typically less liquid than stocks that trade on the NYSE. Trading on the over-the-counter market may negatively affect the trading price and liquidity of the Trust units and could result in larger spreads in the bid and ask prices for Trust units. Unit holders may find it difficult to resell their Trust units due to the delisting.
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The reserves attributable to the underlying properties are depleting assets and production from those reserves will diminish over time. Furthermore, the Trust is precluded from acquiring other oil and natural gas properties or NPI to replace the depleting assets and production.
The net proceeds payable to the Trust from the NPI are derived from the sale of oil, natural gas and natural gas liquids produced from the underlying properties. The reserves attributable to the underlying properties are depleting assets, which means that such reserves will decline over time. Based on the reserve report, overall production for both oil and gas attributable to the underlying properties is expected to decline at an average year-over-year rate of approximately 13.3% for oil and 25.9% for gas between 2018 and 2021, assuming the level of developmental drilling and investments on the underlying properties as assumed in the year-end reserve report. However, cash distributions to unitholders may decline at a faster rate than the rate of production due to fixed and semi-variable costs attributable to the underlying properties or if expected future development is delayed, reduced or cancelled. Also, the anticipated rate of decline is an estimate and actual decline rates will likely vary from those estimated. As of December 31, 2017, the percentage of remaining reserves expected to be produced during the term of the NPI was 43.4%. The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), or (b) the sale of the net profits interest.
Future maintenance projects on the underlying properties beyond those which are currently estimated may affect the quantity of proved reserves that can be economically produced from the underlying properties. The timing and size of these projects will depend on, among other factors, the market prices of oil, natural gas and natural gas liquids. If operators of the underlying properties do not implement required maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by Whiting or estimated in the reserve report. Additionally, although Whiting retained a 10% interest in the net proceeds from the sale of oil, natural gas and natural gas liquids from the underlying properties, Whiting does not own any Trust units, which could reduce its economic incentive to operate the underlying properties in an efficient and cost-effective manner.
The Trust agreement provides that the Trust’s business activities are limited to owning the NPI and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyance related to the NPI. As a result, the Trust is not permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets or production attributable to the NPI, nor is the Trust permitted to enter into any new hedging arrangements.
Because the net proceeds payable to the Trust are derived from the sale of depleting assets, the portion of the distributions to unitholders attributable to depletion should be considered a return of capital as opposed to a return on investment. Eventually, the NPI may cease to produce in commercial quantities and the Trust may, therefore, cease to receive any distributions of net proceeds therefrom. Further, distributions will cease upon termination of the Trust.
Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the Trust units.
The value of the Trust units and the amount of future cash distributions, if any, to the Trust unitholders depends upon, among other things, the accuracy of the production and reserves estimated to be attributable to the underlying properties and the NPI. Estimating production and reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates, and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating production and reserves. Those factors and assumptions include:
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historical production from the area compared with production rates from other producing areas;
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the assumed effect of governmental regulation; and
			
		
			
		
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assumptions about future prices of oil, natural gas and natural gas liquids, including differentials, production and development costs, gathering and transportation costs, severance and excise taxes and capital expenditures.
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Changes in these assumptions may materially alter production and reserve estimates. The estimated proved reserves attributable to the NPI and the “standardized measure” value attributable to the NPI are based on estimates of reserve quantities and revenues for the underlying properties. The quantities of reserves attributable to the underlying properties and the NPI may decrease in the future as a result of future decreases in the price of oil, natural gas or natural gas liquids. For example, the reserve estimates in the reserve report have been derived from NYMEX oil and gas prices of $51.34 per Bbl and $2.98 per MMBtu, respectively, which are calculated using an average of the first-day-of-the month price for each month within the 12 months ended December 31, 2017, pursuant to current SEC and FASB guidelines.
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Financial returns to purchasers of Trust units will vary in part based on how quickly 11.79 MMBOE are produced from the underlying properties and sold, and it is not known when that will occur.
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The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold, or (b) the sale of the net profits interest. The reserve report currently projects that 11.79 MMBOE will have been produced from the underlying properties prior to December 31, 2021. As basis for comparison, the estimated date when such amount would have been produced according to the 2016 year-end reserve report was July 31, 2023. However, the exact rate of production cannot be predicted with certainty and such amount may be produced before or after that date. If production attributable to the underlying properties is slower than estimated, then financial returns to purchasers of Trust units will be lower (assuming constant prices) because cash distributions attributable to such production will occur at a later date.
There will be no distribution to unitholders when the amount of any costs, expenses and reserves related to the underlying properties, other costs and expenses incurred by the Trust and prior period net losses and applicable accrued interest, exceeds or equals the gross proceeds generated by the NPI, as occurred for the February 2016 net loss, May 2016 net loss and August 2016 distribution.
The NPI bears its share of all production and development costs and expenses related to the underlying properties, such as lease operating expenses, production and property taxes and development costs, which reduces or potentially eliminates the amount of cash received by the Trust and thereafter distributable to Trust unitholders. Additionally, if production and development costs on the underlying properties exceed the proceeds from production, as occurred for the February 2016 and May 2016 net losses when the NPI generated an aggregate $1.3 million net loss attributable to the Trust’s interest, the Trust will not receive net proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest during the deficit period. Also, amounts may be reserved by Whiting for future development, maintenance or operating expenses (which reserve amounts may not exceed $2.0 million), which also reduces the amount of cash received by the Trust and thereafter be distributable to Trust unitholders.
Accordingly, higher production and development costs and expenses related to the underlying properties directly decreases the amount of cash received by the Trust in respect of its NPI. In addition, cash available for distribution by the Trust is further reduced by the Trust’s general and administrative expenses. If the Trust does not receive net proceeds pursuant to the NPI, or if such net proceeds are reduced, the Trust will not be able to distribute cash to the Trust unitholders, or such cash distributions will be reduced, respectively.
Risks associated with the production, gathering, transportation and sale of oil, natural gas and natural gas liquids could adversely affect cash distributions by the Trust and the value of the Trust units.
The revenues of the Trust, the value of the Trust units and the amount of cash distributions to the Trust unitholders depends upon, among other things, oil, natural gas and natural gas liquids production and the prices received and the costs incurred to exploit oil and natural gas reserves attributable to the underlying properties. Drilling, production or transportation accidents that temporarily or permanently halt the production and sale of oil, natural gas and natural gas liquids at any of the underlying properties reduces Trust distributions by reducing the amount of net proceeds available for distribution. For example, accidents may occur that result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any costs incurred in connection with any such accidents that are not insured against will have the effect of reducing the net proceeds available for distribution to the Trust. Also, Whiting does not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. Refer to the risk factor entitled “Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affecting Whiting’s and other operators’ services.” for a discussion of the uncertainty involved in the regulation of hydraulic fracturing. Also, Whiting’s oil, natural gas liquids and natural gas production depends in large part on the proximity and capacity of
			
		
			
		
pipeline systems and transportation facilities which are mostly owned by third parties. The lack of availability or the lack of capacity on these systems and facilities could result in the curtailment of production or the delay or discontinuance of drilling plans. Similarly, curtailments or damage to pipelines and other transportation facilities used to transport oil, natural gas and natural gas liquids production to markets for sale could reduce the amount of net proceeds available for distribution. Any such curtailment or damage to the gathering systems could also require finding alternative means to transport the oil, natural gas and natural gas liquids production from the underlying properties, which alternative means could result in additional costs that will have the effect of reducing net proceeds available for distribution.
Also, in response to recent accidents involving rail cars carrying Bakken crude oil, the U.S. Department of Transportation (the “DOT”) issued an emergency order on February 25, 2014 that requires rail shippers to test the makeup of such crude oil before transporting it. This move follows the safety alert the DOT issued in January 2014 that Bakken formation crude oil is more flammable than other types of crude oil and has been followed by additional emergency orders and safety advisories and alerts. An accident involving rail cars could result in significant personal injuries and property and environmental damage. In May 2015, the Pipeline and Hazardous Material Safety Administration issued new rules applicable to “high-hazard flammable trains”, which could increase transportation expenses. Similarly, regulatory responses to the October 2015 failure at a Southern California underground natural gas storage facility could also lead to increased expenses for underground storage.
In addition, drilling, production and transportation of hydrocarbons bear the inherent risk of loss of containment. Potential consequences include loss of reserves, loss of production, loss of economic value associated with the affected wellbore, contamination of air, soil, ground water, and surface water, as well as potential fines, penalties or damages associated with any of the foregoing consequences.
The market price for the Trust units may not reflect the value of the NPI held by the Trust and, in addition, over time will decline to zero around or shortly after the NPI termination date, which is currently estimated to be December 31, 2021.
The trading price for publicly traded securities similar to the Trust units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the Trust will vary in response to numerous factors outside the control of the Trust, including prevailing sales prices of oil, natural gas and natural gas liquids production attributable to the underlying properties. Further, the market price of Trust units may be affected by factors other than the anticipated future Trust distributions. Consequently, the market price for the Trust units may not necessarily be indicative of the value that the Trust would realize if it sold the NPI to a third-party buyer. In addition, such market price may not necessarily reflect the fact that since the assets of the Trust are depleting assets, a portion of each cash distribution paid, if any, on the Trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. As a result, distributions made to a unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the unitholder, and over time the market price of the Trust units will decline to zero around or shortly after the NPI termination date, which is currently estimated to be December 31, 2021 based on the reserve report as of December 31, 2017.
Whiting has limited control over activities on the underlying properties that Whiting does not operate, which could reduce production from the underlying properties, increase capital expenditures and reduce cash available for distribution to Trust unitholders.
Whiting is currently designated as the operator of 65% of the underlying properties based on the standardized measure of discounted future net cash flows at December 31, 2017. However, for the 35% of the underlying properties that it does not operate, Whiting does not have control over normal operating procedures, expenditures or future development relating to such properties. The failure of an operator to adequately perform operations or an operator’s breach of the applicable agreements could reduce production from the underlying properties and the cash available for distribution to Trust unitholders. The success and timing of operational activities on properties operated by others therefore depends upon a number of factors outside of Whiting’s control, including the operator’s decisions with respect to the timing and amount of capital expenditures, the period of time over which the operator seeks to generate a return on capital expenditures, the inclusion of other participants in drilling wells, and the use of technology, as well as the operator’s expertise and financial resources and the operator’s relative interest in the underlying field. Operators may also opt to decrease operational activities following a significant decline in oil or natural gas prices. Because Whiting does not have a majority interest in most of the non-operated properties comprising the underlying properties, Whiting may not be in a position to remove the operator in the event of poor performance. Accordingly, while Whiting has agreed to use commercially reasonable efforts to cause the operator to act as a reasonably prudent operator, it is limited in its ability to do so.
			
		
			
		
The processes of drilling and completing wells are high risk activities.
The processes of drilling and completing wells are subject to numerous risks beyond the Trust’s and Whiting’s control, including risks that could delay the current drilling schedule of Whiting or any other operator of an underlying property and the risk that drilling will not result in commercially viable production. Neither Whiting nor any other operator is obligated to undertake any development activities, so any drilling and completion activities are subject to their discretion. Further, Whiting’s or any other operator’s future business, financial condition, results of operations, liquidity or ability to finance its share of planned development expenditures could be materially and adversely affected by any factor that may curtail, delay or cancel drilling, including the following:
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substantial or extended declines in oil, NGL and natural gas prices;
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delays imposed by or resulting from compliance with regulatory requirements;
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delays in or limits on the issuance of drilling permits on federal leases, including as a result of government shutdowns;
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pressure or irregularities in geological formations;
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shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs, completion services and CO2;
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equipment failures or accidents;
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adverse weather conditions, such as freezing temperatures, hurricanes and storms;
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pipeline takeaway and refining and processing capacity; and
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title problems.
In the event that development activities are delayed or cancelled, or development wells have lower than anticipated production, due to one or more of the factors above or for any other reason, estimated future distributions to unitholders may be reduced.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affecting Whiting’s and other operators’ services.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. Hydraulic fracturing has been utilized during the completion of wells drilled on the underlying properties, and Whiting expects it will also be used in the future. The process involves the injection of mainly water and sand plus a de minimis amount of chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA has also issued guidance in 2014 for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel.
In December 2016, the EPA released a final report on the potential impacts of oil and gas fracturing activities on the quality and quantity of drinking water resources in the United States.
In addition, in June 2016 the EPA issued a final rule promulgating pretreatment standards for the oil and gas extraction category which addresses discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. Unconventional oil and gas extraction facilities can send wastewater to a private wastewater treatment facility that can either discharge treated water or send it to a publicly-owned treatment works. The EPA is also conducting a study of private wastewater treatment facilities accepting oil and gas extraction wastewater. The EPA is collecting data and information regarding the extent to which these facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of the facilities, the environmental impacts of discharges and other information.
Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy, the U.S. Government Accountability Office and the White House Council for Environmental Quality. In March 2015, the U.S. Department of the Interior released a final rule addressing (i) hydraulic fracturing on federal and Indian oil and natural gas leases to require validation of well integrity and strong cement barriers between the wellbore and water zones through which the wellbore passes, (ii) disclosure of chemicals used in hydraulic fracturing to the Bureau of Land Management, (iii) higher standards for interim storage of recovered waste fluids from hydraulic fracturing and (iv) measures to lower the risk of cross-well contamination with chemicals and fluids used in fracturing operations. This rule was challenged in federal court and in June 2016, the Wyoming District Court hearing the case ruled that the Department of the Interior had exceeded its authority in issuing the rule. In March 2017, Justice Department lawyers representing the Bureau of Land Management asked the Court of Appeals for the Tenth Circuit to stay the government’s previously filed appeal as the Trump Administration was planning to rescind the rules; and in July 2017, the Department of the Interior announced its proposal to rescind the rules, with the public comment period on the proposal closing in September 2017. On December 29, 2017, the Department of the Interior issued a final rule rescinding the 2015 rule.
			
		
			
		
In addition, legislation has been introduced in Congress from time to time to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that could ban, restrict or impose additional requirements on activities relating to hydraulic fracturing in certain circumstances. For example, in June 2011, Texas enacted a law that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production in Texas) and the public. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting requirements or operational restrictions and also to associated permitting delays, litigation risk and potential increases in costs. Further, local governments may seek to adopt, and some have adopted, ordinances within their jurisdictions restricting the use of or regulating the time, place and manner of drilling or hydraulic fracturing. No assurance can be given as to whether or not similar measures might be considered or implemented in the jurisdictions in which the underlying properties are located. If new laws, regulations or ordinances that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in the states or local municipalities where the underlying properties are located, such legal requirements could prohibit or make it more difficult or costly for Whiting to perform hydraulic fracturing activities on the underlying properties and thereby could affect the determination of whether a well is commercially viable. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that Whiting is ultimately able to produce in commercially paying quantities from the underlying properties and could reduce cash distributions by the Trust and the value of Trust units.
In addition, in July 2014, a major university and U.S. Geological Survey researchers published a study purporting to find a causal connection between the deep well injection of hydraulic fracturing wastewater and a sharp increase in seismic activity in Oklahoma since 2008. This study, as well as subsequent studies and reports may trigger new legislation or regulations that would limit or ban the disposal of hydraulic fracturing wastewater in deep injection wells. If such new laws or rules are adopted, operations on the underlying properties may be curtailed while alternative treatment and disposal methods are developed and approved, or the costs of operations on the underlying properties may increase, which could reduce cash distributions by the Trust and the value of Trust units.
The Trust and the Trust unitholders have no voting or managerial rights with respect to the underlying properties. As a result, neither the Trust nor the Trust unitholders have any ability to influence the operation of the underlying properties.
Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners of oil and natural gas properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. Neither the Trustee nor the Trust unitholders have any contractual ability to influence or control the field operations of, and sale of oil and natural gas from, the underlying properties, including underlying properties where Whiting is the operator. Also, the Trust unitholders have no voting rights with respect to the operators of these properties and, therefore, have no managerial, contractual or other ability to influence the activities of the operators of these properties.
The Trust’s NPI may be characterized as an executory contract in bankruptcy, which could be rejected in bankruptcy, thus relieving Whiting from its obligations to make payments to the Trust with respect to the NPI.
Whiting has recorded the conveyance of the NPI in the states where the underlying properties are located in the real property records in each county where these properties are located. The NPI is a non-operating, non-possessory interest carved out of the oil and natural gas leasehold estate, but certain states have not directly determined whether a NPI is a real or a personal property interest. Whiting believes that the delivery and recording of the conveyance should create a fully conveyed and vested property interest under the applicable state’s laws, but certain states have not directly determined whether this would be the result. If in a bankruptcy proceeding in which Whiting becomes involved as a debtor a determination were made that the conveyance constitutes an executory contract and the NPI is not a fully conveyed property interest under the laws of the applicable state, and if such contract were not to be assumed in a bankruptcy proceeding involving Whiting, the Trust would be treated as an unsecured creditor of Whiting with respect to the NPI in the pending bankruptcy proceeding.
			
		
			
		
Whiting or other operators may abandon individual wells or properties that it or they reasonably believe to be uneconomic.
Whiting or other operators may abandon any well if it or they reasonably believe that the well can no longer produce oil or natural gas in commercially economic quantities. This could result in termination of the NPI relating to the abandoned well.
An increase in the differential or decrease in the premium between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price received could reduce cash distributions by the Trust and the value of Trust units.
Oil and natural gas production from the underlying properties generally trades at a discount, but sometimes at a premium, to the relevant benchmark prices, such as NYMEX. A negative difference between the benchmark price and the price received is called a differential and a positive difference is called a premium. The differential and premium may vary significantly due to market conditions, the quality and location of production and other risk factors. Whiting cannot accurately predict oil and natural gas differentials or premiums. Increases in the differential and decreases in the premiums between the benchmark price for oil and natural gas and the wellhead price received could reduce cash distributions by the Trust and the value of the Trust units.
The Trust units may lose value as a result of title deficiencies with respect to the underlying properties.
The existence of a material title deficiency with respect to the underlying properties could reduce the value of a property or render it worthless, thus adversely affecting the NPI and distributions to Trust unitholders. Whiting does not obtain title insurance covering mineral leaseholds, and Whiting’s failure to cure any title defects may cause Whiting to lose its rights to production from the underlying properties. In the event of any such material title problem, proceeds available for distribution to Trust unitholders and the value of the Trust units may be reduced.
Conflicts of interest could arise between Whiting and the Trust unitholders.
The interests of Whiting and the interests of the Trust and the Trust unitholders with respect to the underlying properties could at times differ. For example:
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Whiting’s interests may conflict with those of the Trust and the Trust unitholders in situations involving the development, maintenance, operation or abandonment of certain wells on the underlying properties for which Whiting acts as the operator. Whiting may also make decisions with respect to development costs that adversely affect the underlying properties. These decisions include reducing development costs on properties for which Whiting acts as the operator, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future. Additionally, Whiting’s broad discretion over the timing and amount of development, maintenance, operating expenditures and activities could result in higher costs being attributed to the NPI.
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In the event the Trust is required to sell the NPI because (i) annual cash proceeds to the Trust from the net profits interest are less than $2.0 million for each of any two consecutive years or (ii) Trust unitholders vote to sell the NPI, Whiting may seek to purchase the NPI from the Trust. Although the Trustee has certain obligations to unitholders in connection with the sale of the NPI, there is likely a limited universe of potential buyers given the terms of the net profits interest and Whiting’s residual interest in the underlying properties.
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Whiting has the right, subject to significant limitations as described herein, to cause the Trust to release a portion of the NPI in connection with a sale of a portion of the oil and natural gas properties comprising the underlying properties to which the NPI relates. In such an event, the Trust is entitled to receive its proportionate share of the proceeds from the sale attributable to the NPI released.
·
The Trust has no employees and is reliant on Whiting’s employees to operate those underlying properties for which Whiting is designated as the operator. Whiting’s employees are also responsible for the operation of other oil and gas properties Whiting owns, which may require a significant portion or all of their time and resources.
The documents governing the Trust generally do not provide a mechanism for resolving these conflicting interests.
The Trust is managed by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.
The business and affairs of the Trust are administered by the Trustee. The voting rights of a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The Trust agreement provides that the Trustee may only be removed and
			
		
			
		
replaced by a vote of the holders of a majority of the outstanding Trust units at a special meeting of Trust unitholders called by either the Trustee or the holders of not less than 10% of the outstanding Trust units. As a result, it may be difficult to remove or replace the Trustee.
Trust unitholders have limited ability to enforce provisions of the NPI.
The Trust agreement permits the Trustee to sue Whiting on behalf of the Trust to enforce the terms of the conveyance creating the NPI. If the Trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of a Trust unitholder would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The Trust agreement expressly limits the Trust unitholders’ ability to directly sue Whiting or any other third party other than the Trustee. As a result, the unitholders are not able to sue Whiting to enforce these rights.
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Under certain circumstances, the Trust provides that the Trustee may be required to sell the NPI and dissolve the Trust prior to the expected termination of the Trust. As a result, Trust unitholders may not recover their investment.
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The Trust is required to sell the NPI and liquidate if cash proceeds to the Trust from the net profits interest are less than $2.0 million for each of any two consecutive years. During the years ended December 31, 2017 and 2016, the Trust received cash proceeds of $6.7 million and $1.9 million, respectively, from the net profits interest. Additionally, the Trustee must sell the NPI if the holders of a majority of the Trust units approve the sale or vote to dissolve the Trust. The sale of the NPI will result in the dissolution of the Trust and the net proceeds of any such sale will be distributed to the Trust unitholders.
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The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), or (b) the sale of the net profits interest. The Trust unitholders will not be entitled to receive any net proceeds from the sale of production from the underlying properties following the termination of the NPI. Therefore, the market price of the Trust units will approach and eventually reach zero shortly after the end of the NPI term because cash distributions from the Trust will cease following the termination of the NPI, and the Trust will have no right to any additional production from the underlying properties after the term of the NPI.
Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.
Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations under the General Corporation Law of the State of Delaware. Courts in jurisdictions outside of Delaware, however, may not give effect to such limitation.
The operations of the underlying properties may result in significant costs and liabilities with respect to environmental and operational safety matters, which could reduce the amount of cash available for distribution to Trust unitholders.
Significant costs and liabilities can be incurred as a result of environmental and safety requirements applicable to the oil and natural gas exploration, development and production activities of the underlying properties. These costs and liabilities could arise under a wide range of federal, regional, state and local environmental and safety laws, regulations, and enforcement policies, which legal requirements have tended to become increasingly strict over time. Numerous governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts on the operations of the underlying properties.
Although President Trump has indicated that he would work to ease regulatory burdens on industry and on the oil and gas sector, including environmental regulations, any executive orders the President may issue or any new legislation Congress may pass with the goal of reducing environmental statutory or regulatory requirements may be challenged in court. In addition, various state laws and regulations (and permits issued thereunder) will be unaffected by federal changes unless and until the state laws and corresponding permits are similarly changed, and any judicial review is completed.
Strict, joint and several liability may be imposed under certain environmental laws and regulations, which could result in liability being imposed on Whiting with respect to its portion of the underlying properties due to the conduct of others or from Whiting’s
			
		
			
		
actions even if such actions were in compliance with all applicable laws at the time those actions were taken. Private parties, including the surface estate owners of the real properties at which the underlying properties are located and the owners of facilities where petroleum hydrocarbons or wastes resulting from operations at the underlying properties are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damages. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If it were not possible to recover the resulting costs for such liabilities or non-compliance through insurance or increased revenues, then these costs could have a material adverse effect on the cash distributions to the Trust unitholders.
The Trust bears indirectly 90% of all costs and expenses paid by Whiting, including those related to environmental compliance and liabilities associated with the underlying properties. In addition, as a result of the increased cost of compliance, the operators of the underlying properties may decide to discontinue drilling.
The operations of the underlying properties are subject to complex federal, state, local and other laws and regulations that could adversely affect cash distributions to the Trust unitholders.
The development and production operations of the underlying properties are subject to complex and stringent laws and regulations. In order to conduct the operations of the underlying properties in compliance with these laws and regulations, Whiting and the other operators must obtain and maintain numerous permits, approvals and certificates from various federal, state, local and governmental authorities. Whiting and the other operators may incur substantial costs and experience delays in order to maintain compliance with these existing laws and regulations, which could decrease the cash distributions to the Trust unitholders. In addition, the costs of compliance may increase or the operations of the underlying properties may be otherwise adversely affected if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to such operations. Such costs could have a material adverse effect on the cash distributions to the Trust unitholders.
The operations of the underlying properties are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on the cash distributions to the Trust unitholders.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for oil and gas which could reduce the amount of cash available for distribution to Trust unitholders.
In December 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. Based on these findings, the EPA has adopted and implemented regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, as amended (the “CAA”), including rules that limit emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger the CAA construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards took effect in January 2011. In June 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (the “PSD”) and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Further, facilities required to obtain PSD permits for their GHG emissions are required to reduce those emissions consistent with guidance for determining “best available control technology” standards for GHG, which guidance was published by the EPA in November 2010. Also in November 2010, the EPA expanded its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis.
In June 2014, the Supreme Court upheld most of the EPA’s GHGs permitting requirements, allowing the agency to regulate the emission of GHGs from stationary sources already subject to the PSD and Title V requirements. Certain of Whiting’s equipment and installations may currently be subject to PSD and Title V requirements and hence, under the Supreme Court’s ruling, may also be subject to the installation of controls to capture GHGs. For any equipment or installation so subject, Whiting may have to incur increased compliance costs to capture related GHGs emissions, which could reduce cash distributions by the Trust and the value of Trust units.
			
		
			
		
In October 2016, EPA proposed revisions to the rule applicable to GHGs for PSD and Title V permitting requirements. On November 18, 2016, the EPA extended the public comment period for the rulemaking to December 16, 2016. The proposed rule, which would not expand federal GHG permitting requirements, has not yet been finalized.
The EPA announced in 2015 that it would directly regulate methane emissions from oil and natural gas wells for the first time as part of President Obama’s Climate Action Plan. As part of this strategy, in May 2016, the EPA issued a final rule that updated the New Source Performance Standards to add requirements that the oil and gas industry reduce emissions of greenhouse gases and to cover additional equipment and activities in the oil and gas production chain. The final rule sets emissions limits for methane, which is the principal greenhouse gas emitted by equipment and processes in the oil and gas sector. This rule applies to new, reconstructed and modified processes and equipment.
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In accordance with President Obama’s Climate Action Plan, in August 2015, the EPA issued a rule to reduce carbon emissions from electric generating units. The rule, commonly called the “Clean Power Plan,” requires states to develop plans to reduce carbon emissions from fossil fuel-fired generating units commencing in 2022, with the reductions to be fully phased in by 2030. Each state is given a different carbon reduction target, but the EPA expects that, in the aggregate, the overall proposal will reduce carbon emissions from electric generating units by 32% from 2005 levels. States are given substantial flexibility in meeting their emission reduction targets and can generally choose to lower carbon emissions by replacing higher carbon generation, such as coal or natural gas, with lower carbon generation, such as efficient natural gas units or renewable energy alternatives. Several industry groups and states have challenged the Clean Power Plan in the Court of Appeals for the D.C. Circuit, and in February 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan while it is being challenged in court. The Court of Appeals for the D.C. Circuit heard oral arguments on the Clean Power Plan in September 2016, but has not yet issued a decision. On March 28, 2017, the Trump Administration issued an executive order directing the EPA to review the Clean Power Plan. On the same day, the EPA filed a motion in the U.S. Court of Appeals for the D.C. Circuit requesting that the court hold the case in abeyance while the EPA conducts its review of the Clean Power Plan. On October 16, 2017, the EPA published a proposed rule that would repeal the Clean Power Plan. The EPA also stated in the proposed rule that the agency has not determined the scope of any rule to regulate GHG emissions from existing electric generating units, but intends to issue an Advance Notice of Proposed Rulemaking “in the near future.” Several states have already announced their intention to challenge any repeal of the Clean Power Plan. It is not yet clear what changes, if any, will result from the EPA’s proposal, whether or how the courts will rule on the legality of the Clean Power Plan, the EPA’s repeal of the rules, or any future replacement.
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In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and many states have already taken legal measures to reduce emissions of GHGs, primarily through the development of GHG inventories, GHG permitting and/or regional GHG cap-and-trade programs. Most of these cap-and-trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. In the absence of new legislation, the EPA is issuing new regulations that limit emissions of GHGs associated with the operations of the underlying properties, which will require Whiting to incur costs to inventory and reduce emissions of GHGs associated with the operations of the underlying properties and that could adversely affect demand for oil, natural gas liquids and natural gas produced. Finally, it should be noted that many scientists have concluded that increasing concentrations of GHGs in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on the Trust’s assets and the amount of cash available for distribution to the Trust unitholders.
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Shortages or increases in costs of oil field equipment, services, qualified personnel and supply materials could delay production, thereby reducing the amount of cash available for distribution.
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The demand for qualified and experienced field personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs, completion crews and other oil field equipment as demand for these items has increased along with the number of wells being drilled and completed. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs and other oil field goods and services. Additionally, operations on the underlying properties in some instances require supply materials such as CO2 for production which could become subject to shortage and increasing costs. Shortages of field personnel, drilling rigs, completion crews, equipment, supplies or personnel or price increases could delay or adversely affect the amount of cash available for distribution to the Trust unitholders, or restrict operations on the underlying properties.
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If the financial position of Whiting degrades in the future, Whiting may not be able to satisfy its obligations to the Trust.
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Whiting operates approximately 65% of the underlying properties based on the standardized measure of discounted future net cash flows at December 31, 2017. The conveyance provides that Whiting will be obligated to market, or cause to be marketed, the production related to underlying properties for which it operates.
Whiting’s ability to perform its obligations related to the operation of the underlying properties and its obligations to the Trust will depend on Whiting’s future financial condition and economic performance, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and upon financial, business and other factors, many of which are beyond the control of Whiting. Whiting cannot provide any assurance that its financial condition and economic performance will not deteriorate in the future. A substantial or extended decline in oil or natural gas prices may materially and adversely affect Whiting’s future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
The financial results of the Trust may differ from the financial results of Whiting USA Trust I.
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Whiting previously participated in the formation and initial public offering of Whiting USA Trust I (“Trust I”) on April 30, 2008 and Trust I terminated its NPI effective January 28, 2015 as a result of the contractual volumes being produced and sold from Trust I’s underlying properties. Given the differences in assets comprising the underlying properties, commodity prices, production and development costs, development schedule, operators of the underlying properties and regulatory environment, among other things, the historical results of operations of Whiting USA Trust I should not be relied on as an indicator of how Whiting USA Trust II will perform.
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Under certain circumstances, the Trust provides that the Trustee may be required to reconvey to Whiting a portion of the NPI, which may impact how quickly 11.79 MMBOE are produced from the underlying properties for purposes of the NPI.
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If Whiting is notified by a person with whom Whiting is a party to a contract containing a prior reversionary interest that Whiting is required to convey any of the underlying properties to such person or cease production from any well, then Whiting may provide such conveyance with respect to such underlying property or permanently cease production from such well. Such a reversionary interest typically results from the provisions of a joint operating agreement that governs the drilling of wells on jointly owned property and financial arrangements for instances where all owners may not want to make the capital expenditure necessary to drill a new well. The reversionary interest is created because an owner that does not consent to capital expenditures will not have to pay its share of the capital expenditure, but instead will relinquish its share of proceeds from the well until the consenting owners receive payout (or a multiple of payout) of their capital expenditures. In such case, Whiting may request the Trustee to reconvey to Whiting the NPI with respect to any such underlying property or well. The Trust will not receive consideration for any such reconveyance of a portion of the NPI and, any such reconveyance of a portion of the NPI may extend the time it takes 11.79 MMBOE (10.61 MMBOE at the 90% NPI) to be produced from the underlying properties for purposes of the NPI.
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The Trust has not requested a ruling from the IRS regarding the tax treatment of ownership of the Trust units. If the IRS were to determine (and be sustained in that determination) that the Trust is not a “grantor trust” for federal income tax purposes, or that the NPI is not properly treated as a production payment (and thus could fail to qualify as a debt instrument) for federal income tax purposes, the Trust unitholders may receive different and potentially less advantageous tax treatment than they anticipated.
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If the Trust were not treated as a grantor trust for federal income tax purposes, the Trust should be treated as a partnership for such purposes. Although the Trust would not become subject to federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the Trust unitholders, the Trust’s tax reporting requirements would be more complex and costly to implement and maintain, and its distributions to unitholders could be reduced as a result.
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If the NPI were not treated as a debt instrument, any deductions allowed to an individual Trust unitholder in their recovery of basis in the NPI may be itemized deductions, the deductibility of which would be subject to limitations that may or may not apply depending upon the unitholder’s circumstances.
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Neither Whiting nor the Trustee has requested a ruling from the IRS regarding these tax questions, and neither Whiting nor the Trust can assure that such a ruling would be granted if requested or that the IRS will not challenge this position on audit.
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Thus, no assurance can be provided that the opinions and statements set forth in the discussion of U.S. federal income tax consequences would be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the Trust units and the prices at which Trust units trade. In addition, the costs of any contest with the IRS (whether or not such challenge is successful), principally legal, accounting and related fees, will result in a reduction in cash available for distribution to the Trust unitholders, and thus will be borne indirectly by the Trust unitholders.
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Trust unitholders should be aware of the possible state tax implications of owning Trust units, and should consult their own tax advisors for advice regarding the state as well as federal tax implications of owning Trust units.
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The Trust allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record ownership of the Trust units on the quarterly record date, instead of on the basis of the date a particular Trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the Trust unitholders.
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The Trust generally allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record ownership of the Trust units on the quarterly record date, instead of on the basis of the date a particular Trust unit is transferred. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the Trust should be determined and allocated on a daily, prorated or other basis, which could require adjustments to the tax returns of the Trust unitholders affected by the issue and result in an increase in the administrative expense of the Trust in subsequent periods.
The tax treatment of an investment in Trust units could be affected by future legislative, judicial or administrative changes and differing opinions, possibly on a retroactive basis.
The U.S. federal income tax treatment of an investment in the Trust may be modified by administrative or legislative changes, or by judicial interpretation, at any time, possibly on a retroactive basis.
Trust unitholders will be required to pay taxes on their share of the Trust’s income even if they do not receive any cash distributions from the Trust.
For income tax purposes, Trust unitholders are treated as if they own the Trust’s taxable asset (which for tax purposes, is a loan receivable owed to the Trust from Whiting) and they receive the Trust’s income and are directly taxable thereon as if no trust were in existence. The Trust unitholders generally do not receive cash distributions from the Trust equal to their share of the Trust’s taxable income or even equal to the actual tax liability that results from that income. Because the Trust typically generates taxable income that is different in amount than the cash the Trust distributes, the Trust unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of the Trust’s taxable income even if they receive no cash distributions from the Trust.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
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Item 2.
Item 2. Properties
Description of the Underlying Properties
The underlying properties consist of Whiting’s net interests in certain oil and natural gas producing properties as of the date of the conveyance of the NPI to the Trust, which properties are located primarily in the Permian Basin, Rocky Mountains, Gulf Coast and Mid-Continent regions of the United States. The underlying properties include interests in 1,312 gross (376.7 net) producing oil and natural gas wells located in 47 predominately mature fields with established production profiles in 10 states. As of December 31, 2017, approximately 98.9% of estimated proved reserves attributable to the Trust were classified as proved developed producing reserves and 1.1% were classified as proved developed non-producing reserves. For the year ended December 31, 2017, the net production attributable to the underlying properties was 1,168 MBOE or 3,199 BOE/d. Whiting operates approximately 65% of the underlying properties based on the December 31, 2017 reserve report standardized measure of discounted future net cash flows.
Whiting’s interests in the oil and natural gas properties comprising the underlying properties require Whiting to bear its proportionate share, along with the other working interest owners, of the costs to develop and operate such properties. Many of the properties comprising the underlying properties that are operated by Whiting are burdened by non-working interests owned by third parties and royalty interests retained by the owners of the land subject to the working interests. The royalty interests typically entitle the landowner to receive at least 12.5% of the revenue derived from oil and natural gas production from wells drilled on the landowner’s land, without any deduction for drilling costs or other costs related to production of oil and natural gas. A working interest percentage represents a working interest owner’s proportionate ownership interest in a property in relation to all other working interest owners in that property, whereas a net revenue interest is a working interest owner’s percentage of production and revenues, after reducing such interest by the percentage of burdens on production such as royalties and overriding royalties.
The NPI entitles the Trust to receive 90% of the net proceeds from the sale of at least 11.79 MMBOE (10.61 MMBOE at the 90% NPI) of production from the underlying properties. As of December 31, 2017, on a cumulative accrual basis 7.95 MMBOE (75%) of the 10.61 MMBOE attributable to the NPI have been produced and sold or divested. The remaining minimum reserve balance of 2.66 MMBOE (at the 90% NPI) is projected to be produced prior to December 31, 2021, based on the Trust’s year-end 2017 reserve report. 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. However, the reserve report is based on the assumptions included therein. Refer to “Risk Factors” in Item 1A of this Annual Report on Form 10-K for additional discussion of those assumptions and their inherent risks. The rate of future production cannot be predicted with certainty, and the Trust’s 10.61 MMBOE may be produced before or after the currently projected date. The proved reserves attributable to the underlying properties include all proved reserves expected to be economically produced during the remaining full life of the properties, whereas the Trust is only entitled to receive 90% of the net proceeds from the sale of production of oil, natural gas and natural gas liquids attributable to the underlying properties during the term of the NPI.
Whiting’s retained interest in the underlying properties, after deducting the NPI, entitles it to 10% of the net proceeds from the sale of oil, natural gas and natural gas liquids production attributable to the underlying properties during the term of the NPI and all of the net proceeds thereafter. This interest retained by Whiting provides it with an incentive to operate (or cause to be operated) the underlying properties in an efficient and cost-effective manner. In addition, Whiting has agreed to operate the properties for which it is the designated operator as a reasonably prudent operator in the same manner that it would operate them if these properties were not burdened by the NPI. Furthermore, for those properties for which it is not the designated operator, Whiting has agreed to use commercially reasonable efforts to cause the operator to operate the property in the same manner. However, Whiting’s ability to cause other operators to take certain actions is limited.
In general, the producing wells to which the underlying properties relate have established production profiles. Based on the reserve report, annual production from the underlying properties is expected to decline at an average year-over-year rate of approximately 13.3% for oil and 25.9% for gas from 2018 through the estimated December 31, 2021 NPI termination date, assuming no additional developmental drilling or investments other than those assumed in the year-end reserve report. However, cash distributions, if any, to unitholders may decline at a faster rate than the rate of production due to fixed and semi-variable costs attributable to the underlying properties or if future development is delayed, reduced, or cancelled.
Reserves
As of December 31, 2017, all of the Trust’s oil and gas reserves are attributable to properties within the United States. The following table summarizes estimated proved reserves and the standardized measure of discounted future net cash flows as of December 31,
			
		
			
		
2017 attributable to (i) the Trust based on the term of its NPI, and (ii) the underlying properties on a full economic life basis (dollars in thousands):
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(1)
Oil and gas reserve quantities have been derived from NYMEX oil and gas prices of $51.34 per Bbl and $2.98 per MMBtu, respectively, which are calculated using an average of the first-day-of-the month price for each month within the 12 months ended December 31, 2017, pursuant to current SEC and FASB guidelines. The average NYMEX oil and gas prices for the month of January 2018 were $63.66 per Bbl and $3.58 per MMBtu, respectively.
(2)
This table does not include any proved undeveloped reserve quantities as of December 31, 2017 primarily because the underlying properties consist of mature producing properties that are essentially fully developed. While technical studies have identified an insignificant number of drilling locations that could meet the criteria of proved undeveloped reserves, such locations are not reflected in the December 31, 2017 reserve report because no future capital has been committed for the development of such reserves on the underlying properties.
(3)
Standardized measure of discounted future net cash flows as of December 31, 2017. No provision for federal or state income taxes has been provided because taxable income is passed through to the unitholders of the Trust. Therefore, the standardized measure of the Trust and of the underlying properties is equal to their corresponding pre-tax PV 10% values.
(4)
The Trust’s estimated proved reserves as of December 31, 2017 on a 90% NPI basis were 3,084 MBOE, which reserve amount includes only those quantities of proved reserves in the underlying properties that are available to satisfy the interests of Trust unitholders and does not include the remaining 10% of proved reserves in the underlying properties to which only Whiting would be entitled.
(5)
The reserves attributable to the underlying properties include all reserves expected to be economically produced during the life of the properties, whereas the Trust is only entitled to receive 90% of the net proceeds from the sale of production of oil, natural gas and natural gas liquids attributable to the underlying properties during the term of the NPI.
(6)
The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when minimum volumes of 10.61 MMBOE attributable to the NPI have been produced from the underlying properties and sold, or (b) the sale of the net profits interest. The December 31, 2017 reserve report projects that the underlying properties will produce the Trust’s minimum volumes prior to December 31, 2021. Since the net profits interest is not expected to contractually terminate until December 31, 2021, the December 31, 2017 reserve report includes 417 MBOE of additional reserves attributable to the 90% NPI in excess of the Trust’s minimum volumes. The reserve report as of December 31, 2016, however, projected that the underlying properties would produce the Trust’s minimum volumes by July 31, 2023, whereby the Trust would only be entitled to receive the minimum volumes of 10.61 MMBOE.
(7)
Oil includes natural gas liquids.
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Proved reserves. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. Oil and gas reserve quantities and related discounted future net cash flows have been derived from oil and gas prices calculated using an average of the first-day-of-the month price for each month within the most recent 12 months, pursuant to current SEC and FASB guidelines. Assumptions used to estimate reserve quantities and related discounted future net cash flows also include costs for estimated future production and development expenditures required to produce the proved reserves as of December 31, 2017. Future net cash flows are discounted at an annual rate of 10%. There is no provision for federal income taxes with respect to the future net cash flows attributable to the underlying properties or to the NPI because future net revenues are not subject to taxation at the Trust level. Refer to “Federal Income Tax Matters” in Item 1 of this Annual Report on Form 10-K for more information.
A rollforward of changes in net proved reserves attributable to the Trust from January 1, 2017 to December 31, 2017, and the calculation of the standardized measure of the related discounted future net revenues are contained in the Supplemental Oil And Gas Reserve Information (Unaudited) in Item 8 of this Annual Report on Form 10-K. Whiting has not filed reserve estimates covering the underlying properties with any other federal authority or agency.
In 2017, revisions to previous estimates increased proved reserves by a net amount of 279 MBOE. Included in these revisions were (i) 418 MBOE of upward adjustments caused by higher oil and gas pricing incorporated into the Trust’s reserve estimates as of December 31, 2017 compared to December 31, 2016 and (ii) 139 MBOE of net downward adjustments attributable to reservoir analysis. In addition, total extensions and discoveries of 138 MBOE in 2017 were attributable to successful drilling in the Keystone South field pursuant to a farm-out agreement.
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Preparation of reserves estimates. Whiting has advised the Trustee that it maintains adequate and effective internal controls over the reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data. All field and reservoir technical information, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land personnel to discuss field performance. Current revenue and expense information is obtained from Whiting’s accounting records, which are subject to their own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Whiting’s current ownership in mineral interests and well production data are also subject to the aforementioned internal controls over financial reporting, and they are incorporated in the reserve database as well and verified to ensure their accuracy and completeness. Once the reserve database has been entirely updated with current information, and all relevant technical support material has been assembled, the Trust’s independent engineering firm Cawley, Gillespie & Associates, Inc. (“CG&A”) meets with Whiting’s technical personnel in Whiting’s Denver office to review field performance. Following this review the reserve database is furnished to CG&A so that they can prepare their independent reserve estimates and final report. Access to Whiting’s reserve database is restricted to specific members of the reservoir engineering department.
CG&A is a Texas Registered Engineering Firm. Our primary contact at CG&A is Mr. W. Todd Brooker, President. Mr. Brooker is a State of Texas Licensed Professional Engineer. Refer to Appendix 1 and Exhibit 99 of this Annual Report on Form 10-K for the Report of Cawley, Gillespie & Associates, Inc. and further information regarding the professional qualifications of Mr. Brooker.
Whiting’s Vice President of Reservoir Engineering and Acquisitions is responsible for overseeing the preparation of the reserves estimates. He has over 33 years of acquisition and reservoir engineering experience, holds a Bachelor’s degree in Petroleum Engineering from the Colorado School of Mines and is a member of the Society of Petroleum Engineers.
As noted above, the current reserve report projects that 10.61 MMBOE attributable to the 90% NPI will be produced from the underlying properties prior to December 31, 2021. The exact rate of production attributable to the underlying properties cannot be accurately predicted as numerous uncertainties are inherent in estimating reserve volumes and values, and such estimates are subject to change as additional information becomes available. The quantity of reserves actually recovered and the timing of their production may vary significantly from these estimates.
Producing Acreage and Well Counts
For the following data, “gross” refers to the total wells or acres in the oil and natural gas properties in which Whiting owns a working interest and “net” refers to gross wells or acres multiplied by the percentage working interest owned by Whiting and in turn attributable to the underlying properties. Although many of Whiting’s wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas production.
The underlying properties are mainly interests in developed properties located in oil and natural gas producing regions outlined in the chart below. The following is a summary of the number of fields and approximate acreage of these properties by region at December 31, 2017:
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The following is a summary of the producing wells on the underlying properties as of December 31, 2017:
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The following is a summary of the number of productive wells drilled on the underlying properties during the last three years. There were no dry wells drilled on the underlying properties during the years ended December 31, 2017, 2016 and 2015. A productive well is an exploratory, development or extension well that is not a dry well. A dry well is an exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or gas well. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves found.
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(1)
During 2016, a unitization occurred in the Garland field which resulted in an additional nine gross (1.76 net) oil wells being added to the Trust that were previously drilled.
(2)
No exploratory wells were in process of being drilled as of December 31, 2017 and 2015. As of December 31, 2016, one exploratory well was in process of being drilled pursuant to a farm-out agreement in the Keystone South field, which resulted in a productive oil well in 2017.
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As of December 31, 2017, no wells were in the process of being drilled or completed.
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Oil and Natural Gas Production
The following table shows the sales volumes, average sales prices per Bbl of oil and Mcf of natural gas produced and the production costs per BOE for the underlying properties. Sales volumes for natural gas liquids are included with oil sales since they were not material.
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(1)
Oil includes natural gas liquids.
(2)
The Garland, Keystone and Rangely fields were the only fields that contained 15% or more of the total proved reserve volumes of the underlying properties as of December 31, 2017. The Garland and Rangely fields were the only fields that contained 15% or more of the total proved reserve volumes of the underlying properties as of December 31, 2016. The Garland field was the only field that contained 15% or more of the total proved reserve volumes of the underlying properties as of December 31, 2015.
(3)
Production costs reported above exclude from lease operating expenses ad valorem taxes of $1.5 million ($1.28/BOE), $1.4 million ($1.15/BOE) and $1.6 million ($1.10/BOE) for the years ended December 31, 2017, 2016 and 2015, respectively.
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Certain of the Trust’s wells are included in eight separate enhanced oil recovery waterflood projects, which include both secondary (waterflood) and tertiary (CO2 injection) recovery efforts. Aggregate production from such enhanced oil recovery fields averaged 1,072 BOE/d during 2017 or 34% of 2017 daily production from the underlying properties. For these areas, the operator needs to use enhanced recovery techniques in order to maintain oil and gas production from these fields.
Delivery Commitments
Other than the underlying properties’ commitment of 11.79 MMBOE to the Trust pursuant to the terms of the NPI, neither the Trust nor the underlying properties are committed to deliver fixed quantities of oil or natural gas in the future under existing contracts or agreements.
Major Producing Areas
The underlying properties are located in several major onshore producing basins in the continental United States. However, even this broad distribution may not provide protection against regional trends that may negatively impact production or prices. Based on the standardized measure of discounted future net cash flows at December 31, 2017, approximately 65% of these properties were operated by Whiting. Based on annual 2017 production attributable to the underlying properties, approximately 83% of production was crude
			
		
			
		
oil and natural gas liquids and 17% of production was natural gas. These properties are located in mature fields and have established production profiles. However, production and distributions to the Trust will continue to decline over time.
Permian Basin Region. The Permian Basin region is one of the major hydrocarbon producing provinces in the continental United States. The underlying properties in the Permian Basin region are located in Texas and New Mexico. These properties consist of 17 fields of which Whiting operates wells in 12. The major fields in this region, include the Keystone South field that produces from the Clear Fork, Wolfcamp, Wichita Albany and Ellenberger zones; the Martin field that produces from the Clear Fork and Wichita Albany zones; the DEB field that produces from the Wolfcamp zone; the Signal Peak field that produces from the Wolfcamp zone; and the Sable field that produces from the San Andres zone. For the year ended December 31, 2017, the net production attributable to the underlying properties in the region was 538.5 MBOE or 1.5 MBOE/d.
Rocky Mountains Region. The underlying properties in the Rocky Mountains region are located in Colorado, Wyoming, North Dakota and Montana. These properties consist of 14 fields of which Whiting operates wells in four. The Trust’s NPI does not include any of Whiting’s interests in the Bakken and Three Forks formations. The major fields in this region include the Rangely field that produces from the Weber Sand zone; the Garland field that produces from the Madison and Tensleep zones; the Cedar Hills field that produces from the Red River zone; and the Whiting-operated Torchlight field that produces from the Madison and Tensleep zones. For the year ended December 31, 2017, the net production attributable to the underlying properties in the region was 496.0 MBOE or 1.3 MBOE/d.
Gulf Coast Region. The underlying properties in the Gulf Coast region are located in Texas and Mississippi. These properties consist of eight onshore fields, and Whiting operates wells in four. The major field in this region is the Whiting-operated Lake Como field located in Mississippi that produces from the Smackover formation. For the year ended December 31, 2017, the net production attributable to the underlying properties in the region was 109.6 MBOE or 0.3 MBOE/d.
Mid-Continent Region. The underlying properties in the Mid-Continent region are located in Michigan, Arkansas, Oklahoma and Texas. These properties consist of eight fields of which Whiting operates wells in three. The major field in this region is the Whiting-operated Wesson field located in Arkansas that produces from the Hogg Sand zone. For the year ended December 31, 2017, the net production attributable to the underlying properties in the region was 23.6 MBOE or 0.1 MBOE/d.
Abandonment, Sale, and Farm-out of Underlying Properties
Any operator of the underlying properties, including Whiting, has the right to abandon its interest in any well or property comprising a portion of the underlying properties if, in its opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities. To reduce the potential conflict of interest between Whiting and the Trust in determining whether a well is capable of producing in commercially paying quantities, Whiting has agreed to operate the underlying properties as a reasonably prudent operator in the same manner that it would operate these properties if they were not burdened by the NPI. In addition, Whiting has agreed to use commercially reasonable efforts to cause the other operators to operate these properties in the same manner. However, Whiting’s ability to cause other operators to take certain actions is limited. For the years ended December 31, 2017, 2016 and 2015, there were five gross wells in each period that were plugged and abandoned on the underlying properties, based on the determination that such wells were no longer economic to operate.
Divestitures. Whiting may, without the consent of the Trust unitholders, require the Trust to sell the NPI associated with any well or lease that accounts for less than or equal to 0.25% of the total production from the underlying properties in the prior 12 months, provided that the NPI covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the Trust of $1.0 million. These releases will be made only in connection with a sale by Whiting of the relevant underlying properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such portion of the NPI. Any net sales proceeds paid to the Trust are distributable to Trust unitholders for the quarter in which they are received.
No sales of oil and gas wells occurred during the year ended December 31, 2017. During 2016, Whiting completed the sale of three shut-in oil and gas wells (effective for all cost and sales proceeds, if any, beginning September 1, 2016) for a total purchase price of $65,000 ($58,500 to the 90% NPI). The divested properties were located within the Chester and Blair fields in Michigan and had no remaining proved reserves since these wells were being prepared for plugging and abandonment operations by Whiting. In addition, during 2015 Whiting completed the sale of certain producing oil and gas wells for a purchase price of $0.4 million ($0.3 million to the 90% NPI). The divested properties included nine wells located within Cooks Peak field in North Dakota, which had proved reserves of 18.14 MBOE (16.32 MBOE to the 90% NPI).
Farm-out agreements. For the underlying properties for which Whiting is the designated operator, it may enter into farm-out, operating, participation and other similar agreements with respect to the property. Whiting may enter into any of these agreements
			
		
			
		
without the consent or approval of the Trustee or any Trust unitholder. In an effort to develop the underlying properties while limiting additional capital expenditures for the Trust, Whiting Oil and Gas entered into three farm-out agreements with a third-party partner covering (i) 5,127 gross acres in eight leasehold sections within the Keystone South field in Winkler, Texas in April 2016 (the “Keystone South farm-out”), (ii) 9,740 gross acres in approximately 15 units (which unit size is determined by the lateral well length) within the Signal Peak field in Howard County, Texas in February 2017 (the “Signal Peak farm-out”) and (iii) 640 gross acres in one leasehold section within the Flying W, SE field in Winkler County, Texas in March 2017 (the “Flying W farm-out”).
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These farm-out agreements provide the third-party partner with the option, but not the obligation, to drill one well in each of the leasehold sections or units, as the case may be, subject to the applicable farm-out agreement, whereby the partner will pay 100% of the related drilling and well completion costs to earn a 75% working interest. As a result, the applicable underlying properties will consist of (i) 25% of the original working interest in these properties and (ii) an overriding royalty interest equal to the difference between 25% and the lease burdens of record. Upon completion of one well in each section or unit, as the case may be, pursuant to the terms of the applicable agreements, the partner has the option to drill (i) up to 15 additional wells under the Keystone South farm-out, (ii) up to 12 additional wells under the Signal Peak farm-out and (iii) one additional well under the Flying W farm-out. For each of these additional optional wells, the partner is required to pay 85% of the drilling and well completion costs otherwise ascribed to the underlying properties for a 75% working interest. Given the Trust’s interest in the NPI, the Trust would be responsible for 13.5% of the underlying properties’ remaining drilling and well completion costs at the 90% NPI, subject to the average annual capital expenditure amount limitation as described in the “Computation of Net Proceeds” section in Item I of this Annual Report on Form 10-K.
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The third-party partner commenced drilling operations under the Keystone South farm-out agreement in December 2016, and the first three wells were drilled and completed pursuant to the terms of the agreement during the year ended December 31, 2017, whereby the partner earned a 75% working interest in each of the underlying properties’ respective leasehold sections. The third-party partner has no obligation to drill and complete any additional wells. No drilling operations for additional wells have commenced under the Keystone South farm-out, and if no such additional drilling has begun on or before October 2, 2018 the agreement will terminate. In addition, the partner commenced drilling the first well under the Flying W farm-out during March 2018, however, the partner has no obligation to drill any additional wells. No drilling operations have occurred under the Signal Peak farm-out, and if no such drilling has commenced on or before June 1, 2018 the agreement will terminate.
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Title to Properties
The underlying properties are subject to certain burdens that are described in more detail below. To the extent that these burdens and obligations affect Whiting’s rights to production and the value of production from the underlying properties, they have been taken into account in calculating the Trust’s interests and in estimating the size and value of the reserves attributable to the underlying properties.
Whiting’s interests in the oil and natural gas properties comprising the underlying properties are typically subject, in one degree or another, to one or more of the following:
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royalties and other burdens on production, express and implied, under oil and natural gas leases;
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overriding royalties, production payments and similar interests and other burdens on production created by Whiting or its predecessors in title;
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a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect these properties or Whiting’s title thereto;
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liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;
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pooling, unitization and communitization agreements, declarations and orders;
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easements, restrictions, rights-of-way and other matters that commonly affect property;
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conventional rights of reassignment that obligate Whiting to reassign all or part of a property to a third party if Whiting intends to release or abandon such property; and
·
rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the underlying properties and the NPI therein.
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Whiting has informed the Trustee that Whiting believes the burdens and obligations affecting the oil and natural gas properties comprising the underlying properties are conventional in the industry for similar properties. Whiting also has informed the Trustee
			
		
			
		
that Whiting believes that the existing burdens and obligations do not, in the aggregate, materially interfere with the use of the underlying properties and do not materially adversely affect the value of the NPI.
At the time of its acquisitions of the underlying properties, Whiting undertook a title examination of these properties. As such, Whiting has informed the Trustee that Whiting believes its title to the underlying properties is, and the Trust’s title to the net profits interest is, good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions as are not so material to detract substantially from the use or value of such properties or royalty interests.
Net profits interests are non-operating, non-possessory interests carved out of the oil and natural gas leasehold estate, but some jurisdictions have not directly determined whether a NPI is a real or a personal property interest. Whiting has recorded the conveyance of the NPI in the relevant real property records of all applicable jurisdictions. Whiting has informed the Trustee that Whiting believes the delivery and recording of the conveyance creates a fully conveyed and vested property interest under the applicable state’s laws, but because there is no direct authority to this effect in some jurisdictions, this may not always be the result. Whiting has also informed the Trustee that Whiting believes that it is possible the NPI may not be treated as a real property interest under the laws of certain of the jurisdictions where the underlying properties are located. Whiting has also informed the Trustee that Whiting believes that, if, during the term of the NPI, Whiting becomes involved as a debtor in a bankruptcy proceeding, the NPI relating to the underlying properties in most, if not all, of the jurisdictions should be treated as a fully conveyed property interest. In such a proceeding, however, a determination could be made that the conveyance constitutes an executory contract and the NPI is not a fully conveyed property interest under the laws of the applicable jurisdiction, and if such contract were not to be assumed in a bankruptcy proceeding involving Whiting, the Trust would be treated as an unsecured creditor of Whiting with respect to the NPI in the pending bankruptcy proceeding. Although no assurance can be given, Whiting has informed the Trustee that Whiting believes that the conveyance of the NPI relating to the underlying properties in most, if not all, of the jurisdictions of which these properties are located should not be subject to rejection in a bankruptcy proceeding as an executory contract.
Item 3.
Item 3. Legal Proceedings
Currently, there are not any legal proceedings pending to which the Trust is a party or of which any of its property is the subject.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
			
		
			
		
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
The Trust units commenced trading on the New York Stock Exchange on March 23, 2012 under the symbol “WHZ” and were delisted from the New York Stock Exchange on January 6, 2016. The Trust units transitioned to the OTC, operated by OTC Markets Group, effective with the open of trading on January 7, 2016 under the symbol “WHZT”.
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Each quarter, the Trustee determines the amount of funds available for distribution, if any, to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the NPI and other sources (such as interest earned on any amounts reserved by the Trustee) that quarter, over the Trust’s liabilities for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities. Quarterly cash distributions during the term of the Trust are made by the Trustee generally no later than 60 days following the end of each quarter (or the next succeeding business day) to the Trust unitholders of record on the 50th day following the end of each quarter.
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The high and low sales prices per unit, distributable income and distributable income per unit for each quarter in 2017 and 2016 were as follows:
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(1)
Dollars in thousands.
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At December 31, 2017, the 18,400,000 units outstanding were held by two unitholders of record.
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Subsequent to year-end, on March 1, 2018, a distribution of $0.171231 per Trust unit was paid to the Trust unitholders of record on February 19, 2018. This aggregate distribution to all Trust unitholders consisted of net cash proceeds of $3.3 million paid by Whiting to the Trust, less a provision of $0.2 million for estimated Trust expenses and $4,715 for Montana state income tax withholdings.
Equity Compensation Plans
The Trust does not have any employees and, therefore, does not maintain any equity compensation plans.
Recent Sales of Unregistered Securities
None.
Purchases of Equity Securities
There were no purchases of Trust units by the Trust or any affiliated purchaser during the fourth quarter of 2017.
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Item 6.
Item 6. Selected Financial Data
The following table sets forth selected data based on the Trust’s audited financial statements for the periods presented (in thousands, except distributable income per unit and Trust units outstanding data):
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Item 7.
Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations
This document contains forward-looking statements, which include expectations or forecasts of future events. Please refer to “Forward-Looking Statements” which follows the Table of Contents of this Form 10-K for an explanation of these types of statements.
Overview and Trust Termination
The Trust does not conduct any operations or activities. The Trust’s purpose is, in general, to hold the NPI, to distribute to unitholders cash that the Trust receives in respect of the NPI, and to perform certain administrative functions in respect of the NPI and the Trust units. The Trust derives substantially all of its income and cash flows from the NPI, which was in turn subject to commodity hedge contracts through December 31, 2014 (which hedging effects impacted the February 2015 distribution and ceased thereafter). The NPI entitles the Trust to receive 90% of the net proceeds from the sale of production from the underlying properties.
Oil and gas prices historically have been volatile and may fluctuate widely in the future. The table below highlights these price trends by listing quarterly average NYMEX crude oil and natural gas prices for the periods indicated through December 31, 2017. The 2017 NPI distributions are mainly affected, however, by October 2016 through September 2017 oil prices and September 2016 through August 2017 natural gas prices.
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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). If oil, NGL and natural gas prices decline or remain at current levels in future periods, the amount of net proceeds to which the Trust is entitled is likely to be significantly lower than the net proceeds the Trust has received and distributed to Trust unitholders prior to 2015 due to the sustained lower commodity price environment. All costless collar hedge contracts Whiting entered into, and in turn conveyed to the Trust, terminated as of December 31, 2014 (which hedging effects extended through the February 2015 distribution to unitholders) and no additional hedges are allowed to be placed on the Trust assets. Consequently, there 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 November 2017 distribution.
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. During the years ended December 31, 2017 and 2016, the Trust received cash proceeds of $6.7 million and $1.9 million, respectively, from the net profits interest.
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Since the assets of the Trust are depleting assets, a portion of each cash distribution paid, if any, on the Trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment or yield. As a result, the market price of the Trust units will decline to zero at termination of the Trust. As of December 31, 2017, on a cumulative accrual basis, 7.95 MMBOE (75%) of the 10.61 MMBOE attributable to the NPI have been produced and sold or divested. The remaining minimum reserve balance of 2.66 MMBOE (at the 90% NPI) is projected to be produced prior to December 31, 2021, based on the Trust’s year-end 2017 reserve report. 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. For additional discussion relating to the assumptions underlying the estimated date when 11.79 MMBOE (10.61 MMBOE at the 90% NPI) will be produced and sold from the underlying properties, refer to “Description of the Underlying Properties” in Item 2 of this Annual Report on Form 10-K.
			
		
			
		
For a discussion of material changes to proved reserves, refer to “Reserves” in Item 2 of this Annual Report on Form 10-K. Additionally, for a discussion of the need to use enhanced recovery techniques, refer to “Oil and Natural Gas Production” in Item 2 of this Annual Report on Form 10-K.
Capital Expenditure Activities
The primary goal of the planned capital expenditures relative to the underlying properties is to mitigate a portion of the natural decline in production from producing properties. The underlying properties have a capital expenditure budget per the reserve report of $9.0 million estimated to be spent over the remaining four years. No assurance can be given, however, that any such expenditures will be made, or if made, that they 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 the $9.0 million budgeted amount of capital expenditures over such time frame. With respect to the underlying properties, Whiting expects, but is not obligated, to implement the development strategies described below relative to each of the following regions. For fields in which Whiting is not the operator, Whiting will have limited control over the timing and amount of capital expenditures in those areas. Please read “Risk factors - Whiting has limited control over activities on the underlying properties that Whiting does not operate, which could reduce production from the underlying properties, increase capital expenditures and reduce cash available for distribution to Trust unitholders.” Information relating to planned capital expenditures on fields for which Whiting is not the operator represent Whiting’s most recent understanding of the planned expenditures and activities of the operator thereof.
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The following table summarizes the underlying properties’ planned capital expenditures per the reserve report for 2018 through the NPI termination date, which is currently estimated to be December 31, 2021:
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____________
(1)
The planned capital expenditures attributable to the Trust’s 90% net profits interest are $8.1 million.
(2)
The planned capital expenditures for each of the four remaining years of the NPI are below the annual capital expenditure limitation, which limitation became effective January 1, 2018.
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Rocky Mountains Region. The Rangely field, operated by Chevron Corporation, is located in Rio Blanco County, Colorado. This field was discovered in 1931 with development drilling commencing in 1943. The field is currently producing under the tertiary recovery process of CO2 injection. The underlying properties include a 4.6% working interest in the Rangely Weber Sand Unit. Capital is expended each year to purchase CO2 for injection in the field. According to information provided by the operator, the estimated capital expenditures allocated to the underlying properties’ interest are $1.1 million for 2018 and then approximately $1.0 million per year for 2019 through the estimated termination of the NPI. Such capital costs are comprised mainly of CO2 purchases and plant and equipment expenditures. During 2017, Chevron Corporation advised Whiting of a mandatory compliance-driven inspection and maintenance project for the Rangely Weber Sand Unit, which commenced in June 2017 and was completed during July 2017. The cost of the project attributable to the underlying properties was $1.5 million ($1.4 million to the 90% NPI), the vast majority of which were capital expenditures. Whiting is not aware of any other development plans by Chevron at this time, however, Chevron may propose capital expenditures in the future.
Whiting owns a non-operated working interest in the Garland field located in Big Horn County, Wyoming, which produces from the Madison and Tensleep zones. According to information provided by the operator, the estimated capital expenditures allocated to the underlying properties’ interest are $1.0 million per year through the estimated termination of the NPI. Although Whiting is not aware
			
		
			
		
of any other development plans by this operator or other operators of the underlying properties in this region, these operators may propose additional capital expenditures in the future.
Additionally, although Whiting has not identified any future capital expenditures for the Whiting-operated fields in the Rocky Mountains region at this time, further study or offsetting drilling activity may result in capital expenditures in the future.
Permian Basin Region. Whiting operates the DEB field in Gaines County, Texas, which produces from the Wolfcamp zone. Whiting plans to recomplete one shut-in well in this field in 2018 in order to fully recover the remaining reserves. The capital expenditures necessary to perform this recompletion are estimated at approximately $0.7 million allocated to the underlying properties’ interest. Although Whiting has not identified future capital expenditures for any other operated fields in the Permian Basin at this time, further study or offsetting development activity may result in additional capital expenditures in the future. Additionally, although Whiting is not aware of any other development plans by other operators of the underlying properties in the Permian Basin, these operators may propose capital expenditures in the future.
Other Regions. Although Whiting has not identified any future capital expenditures for its operated fields in the Gulf Coast and Mid-Continent regions at this time, further study or offsetting development activity may result in additional capital expenditures in the future. Additionally, although Whiting is not aware of any development plans by other operators of the underlying properties in these regions, operators may propose capital expenditures in the future.
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 beginning December 31, 2017. 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 (the “Signal Peak farm-out”) and (iii) 640 gross acres in one leasehold section within the Flying W, SE field in Winkler County, Texas in March 2017 (the “Flying W farm-out”).
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These farm-out agreements provide the third-party partner with the option, but not the obligation, to drill one well in each of the leasehold sections or units, as the case may be, subject to the applicable farm-out agreement, whereby the partner will pay 100% of the related drilling and well completion costs to earn a 75% working interest. As a result, the applicable underlying properties will consist of (i) 25% of the original working interest in these properties and (ii) an overriding royalty interest equal to the difference between 25% and the lease burdens of record. Upon completion of one well in each section or unit, as the case may be, pursuant to the terms of the applicable agreements, the partner has the option to drill (i) up to 15 additional wells under the Keystone South farm-out, (ii) up to 12 additional wells under the Signal Peak farm-out and (iii) one additional well under the Flying W farm-out. For each of these additional optional wells, the partner is required to pay 85% of the drilling and well completion costs otherwise ascribed to the underlying properties for a 75% working interest. Given the Trust’s interest in the NPI, the Trust would be responsible for 13.5% of the underlying properties’ remaining drilling and well completion costs at the 90% NPI, subject to the average annual capital expenditure amount limitation discussed above.
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The third-party partner commenced drilling operations under the Keystone South farm-out agreement in December 2016, and the first three wells were drilled and completed pursuant to the terms of the agreement during the year ended December 31, 2017, whereby the partner earned a 75% working interest in each of the underlying properties’ respective leasehold sections. The third-party partner has no obligation to drill and complete any additional wells. No drilling operations for additional wells have commenced under the Keystone South farm-out, and if no such additional drilling has begun on or before October 2, 2018 the agreement will terminate. In addition, the partner commenced drilling the first well under the Flying W farm-out during March 2018, however, the partner has no obligation to drill any additional wells. No drilling operations have occurred under the Signal Peak farm-out, and if no such drilling has commenced on or before June 1, 2018 the agreement will terminate.
			
		
			
		
Results of Trust Operations
The following is a summary of income from net profits interest and distributable income received by the Trust for each respective period (dollars in thousands, except per Bbl, per Mcf and per BOE amounts):
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____________
(1)
Oil includes natural gas liquids.
(2)
As discussed in “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Hedge Contracts
The primary asset and source of income to the Trust is the NPI, which generally entitles the Trust to receive 90% of the net proceeds from oil and gas production from the underlying properties. Consequently, the Trust is exposed to market risk from fluctuations in oil and gas prices.
The revenues derived from the underlying properties depend substantially on prevailing crude oil, natural gas and natural gas liquids prices. As a result, commodity prices also affect the amount of cash flow available for distribution to the Trust unitholders. Lower prices may also reduce the amount of oil, natural gas and natural gas liquids that 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 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 8.
Item 8. Financial Statements and Supplementary Data
The following financial statements are set forth under “Financial Statements and Supplementary Data” in Item 8 of this Annual Report on Form 10-K on the pages indicated:
INDEX TO MODIFIED CASH BASIS FINANCIAL STATEMENTS
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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To the Unitholders of Whiting USA Trust II and
The Bank of New York Mellon Trust Company, N.A., as Trustee
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Opinion on the Financial Statements
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We have audited the accompanying statements of assets, liabilities, and trust corpus of Whiting USA Trust II, (“the Trust”) as of December 31, 2017 and 2016, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2017, and related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the assets, liabilities, and trust corpus of the Trust as of December 31, 2017 and 2016, and its distributable income and its changes in trust corpus for each of the three years in the period ended December 31, 2017, in conformity with the modified cash basis of accounting described in Note 2.
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Basis for Opinion
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These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on the Trust's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
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We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion.
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Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
﻿
Basis of Accounting
﻿
As described in Note 2 to the financial statements, these financial statements have been prepared on a modified cash basis of accounting which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.
﻿
/s/ Deloitte & Touche LLP
Austin, Texas
﻿
March 22, 2018
﻿
We have served as the Trust’s auditor since 2011.
			
		
			
		
WHITING USA TRUST II
Statements of Assets, Liabilities and Trust Corpus
(In thousands, except unit data)
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﻿
﻿
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Statements of Distributable Income
(In thousands, except distributable income per unit data)
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﻿
﻿
Statements of Changes in Trust Corpus
(In thousands)
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﻿
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The accompanying notes are an integral part of these modified cash basis financial statements.
			
		
			
		
WHITING USA TRUST II
NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS
1. ORGANIZATION OF THE TRUST
Trust Overview - Whiting USA Trust II (the “Trust”) is a statutory trust formed on December 5, 2011 under the Delaware Statutory Trust Act, pursuant to a trust agreement (the “Trust agreement”) among Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and Wilmington Trust, National Association, as Delaware Trustee (the “Delaware Trustee”). The initial capitalization of the Trust estate was funded by Whiting Petroleum Corporation (“Whiting”) on December 8, 2011.
The Trust was created to acquire and hold a term net profits interest (“NPI”) for the benefit of the Trust unitholders pursuant to a conveyance from Whiting Oil and Gas, a 100%-owned subsidiary of Whiting, to the Trust. The NPI is an interest in certain of Whiting Oil and Gas’ properties located in the Permian Basin, Rocky Mountains, Gulf Coast and Mid-Continent regions of the United States (the “underlying properties”). The NPI is the only asset of the Trust, other than cash reserves held for future Trust expenses. As of December 31, 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. During the years ended December 31, 2017 and 2016, the Trust received cash proceeds of $6.7 million and $1.9 million, respectively, from the net profits interest.
As of December 31, 2017, on a cumulative accrual basis, 7.95 MMBOE (75%) of the 10.61 MMBOE attributable to the NPI have been produced and sold or divested. The portion of Trust reserves divested through December 31, 2017 includes 0.02 MMBOE of proved reserves from certain producing oil and gas wells located within the Cooks Peak field in North Dakota that were sold for a purchase price of $0.4 million ($0.3 million to the 90% NPI) during the first quarter of 2016. Additionally, Whiting divested three shut-in oil and gas wells located within the Chester and Blair fields in Michigan for a purchase price of $65,000 ($58,500 to the 90% NPI) during the fourth quarter of 2016. However, these divested properties had no remaining proved reserves since these wells were being prepared for plugging and abandonment operations by Whiting. The remaining minimum reserve balance of 2.66 MMBOE (at the 90% NPI) is projected to be produced prior to December 31, 2021, based on the Trust’s year-end 2017 reserve report.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Term Net Profits Interest - The Trust uses the modified cash basis of accounting to report Trust receipts from the NPI and payments of expenses incurred. Actual cash distributions to the Trust are made based on the terms of the conveyance that created the Trust’s NPI. The NPI entitles the Trust to receive revenues (oil, gas and natural gas liquid sales) less expenses (the amount by which all royalties; lease operating expenses including well workover costs; development costs; production and property taxes; payments made by Whiting to the hedge counterparty upon settlements of hedge contracts; maintenance expenses; producing overhead; and amounts that may be reserved for future development, maintenance or operating expenses, which reserve amounts may not exceed $2.0 million; 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.
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 of whether the NPI is impaired requires a significant amount of judgment by the Trustee and is based on the best information available to the Trustee at the time of the evaluation.
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While these statements differ from financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues and distributions is considered to be the most meaningful for the Trust’s activities and results because quarterly distributions to the Trust unitholders are based on net cash receipts. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by FASB ASC Topic 932, Extractive Activities - Oil and Gas: Financial Statements of Royalty Trusts.
Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with GAAP, directing such entities to accrue or defer certain revenues and expenses in a period other than when such revenues are received or expenses are paid. Because the Trust’s financial statements are prepared on the modified cash basis as described above, however, most accounting pronouncements are not applicable to the Trust’s financial statements.
Cash and Short-Term Investments - Cash and short-term investments include all highly liquid short-term investments with original maturities of three months or less.
Concentration of Credit Risk - The underlying properties from which the NPI is derived principally sell their oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. The following table presents the percentages by purchaser that accounted for 10% or more of the underlying properties’ total oil and gas sales for the years ended December 31, 2017, 2016 and 2015.
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There is significant competition among purchasers of crude oil and natural gas, and if Whiting were to lose any of its largest purchasers of oil and gas from the underlying properties, several entities could reasonably be expected to purchase crude oil and natural gas produced from the underlying properties with little or no interruption to their sales.
Use of Estimates - The preparation of financial statements requires estimates and assumptions that affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Significant estimates affecting these financial statements include estimates of proved oil and gas reserves, which are used to compute the Trust’s amortization of its investment in net profits interest and its impairment assessments. Although the Trustee believes that these estimates are reasonable, actual results could differ from those estimates.
Recent Accounting Pronouncements - There were no accounting pronouncements issued during the year ended December 31, 2017 applicable to the Trust or its financial statements.
			
		
			
		
3. INVESTMENT IN NET PROFITS INTEREST
Whiting Oil and Gas conveyed the NPI to the Trust in exchange for 18,400,000 Trust units. The investment in net profits interest was recorded at the historical cost basis of Whiting on March 28, 2012, the date of conveyance (except for the derivatives which are reflected at their fair value as of March 31, 2012), 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 was $13.2 million and $7.0 million as of December 31, 2017 and 2016, respectively.
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4. INCOME FROM NET PROFITS INTEREST
The Trust received income from net profits interest as follows:
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____________
(1)
Oil includes natural gas liquids.
(2)
As discussed in “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of this Annual Report on Form 10-K, all costless collar hedge contracts terminated as of December 31, 2014 (which hedging effects extended through the quarterly payment period covered by the February 2015 distribution to unitholders), and no additional hedges are allowed to be placed on Trust assets. Consequently, there are no further cash settlements on commodity hedges, and the Trust will have increased exposure to oil and natural gas price volatility.
(3)
Oil and gas sales volumes and related revenues for the year ended December 31, 2017 (consisting of Whiting’s February 2017, May 2017, August 2017 and November 2017 distributions to the Trust) generally represent crude oil production from October 2016 through September 2017 and natural gas production from September 2016 through August 2017.
(4)
Oil and gas sales volumes and related revenues for the year ended December 31, 2016 (consisting of the February 2016 and May 2016 net losses and August 2016 and November 2016 distributions) generally represent crude oil production from October 2015 through September 2016 and natural gas production from September 2015 through August 2016.
(5)
Oil and gas sales volumes and related revenues for the year ended December 31, 2015 (consisting of Whiting’s February 2015, May 2015, August 2015 and November 2015 distributions to the Trust) generally represent crude oil production from October 2014 through September 2015 and natural gas production from September 2014 through August 2015.
5. INCOME TAXES
The Trust is a grantor trust and therefore is not subject to federal income taxes. Accordingly, no recognition has been given to federal income taxes in the Trust’s financial statements or in the Trust’s standardized measure of discounted future net cash flows. The Trust unitholders are treated as the owners of Trust income and corpus, and the entire taxable income of the Trust is reported by the Trust unitholders on their respective tax returns.
For Montana state income tax purposes, Whiting must withhold from its NPI payments to the Trust, an amount equal to 6% of the net amount payable to the Trust from the sale of oil and gas in Montana. Whiting withheld $12,828, $10,169 and $11,183 related to Montana state income taxes for the years ended December 31, 2017, 2016 and 2015, respectively. For Arkansas, Colorado, Michigan, Mississippi, New Mexico, North Dakota and Oklahoma, neither the Trust nor Whiting is withholding the income tax due such states on distributions made to an individual resident or nonresident Trust unitholder, as long as the Trust is taxed as a grantor trust under the Internal Revenue Code.
			
		
			
		
6. DISTRIBUTION TO UNITHOLDERS
Actual cash distributions to the Trust unitholders depend on the volumes of and prices received for oil, natural gas and natural gas liquids produced from the underlying properties, among other factors. Quarterly cash distributions during the term of the Trust are made by the Trustee no later than 60 days following the end of each quarter (or the next succeeding business day) to the Trust unitholders of record on the 50th day following the end of each quarter. Such amounts equal the excess, if any, of the cash received by the Trust during the quarter, over the expenses of the Trust paid during such quarter, subject to any adjustments for changes made by the Trustee during such quarter to any cash reserves established for future expenses of the Trust or adjustments for the recovery of accumulated net losses and accrued interest.
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Neither the Trust nor the unitholders are liable for any net losses that are generated by the net profits interest; however, any such net losses, plus accrued interest at the prevailing money market rate, are to be recovered by Whiting from future NPI gross proceeds before any further distributions will be made to Trust unitholders, as occurred during the third quarter of 2016. Additionally, if the Trust borrows funds in order to pay its administrative liabilities, the Trust unitholders will not receive distributions until the borrowed funds together with any accumulated net losses and accrued interest are repaid.
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There were no distributions to the Trust unitholders during the first three quarters of 2016 primarily due to the net profits interest generating net losses or limited net proceeds as a result of lower oil and natural gas prices during those quarterly payment periods. The NPI generated net losses of $1.2 million during the second quarter of 2016, which net losses were funded by Whiting at the time they were incurred. All accumulated net losses, plus accrued interest, were recovered by Whiting in full during the third quarter of 2016. There were no accumulated net losses funded or recovered by Whiting during the years ended December 31, 2017 and 2015.
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The following table presents the net profits interest accumulated net losses for the years ended December 31, 2017, 2016 and 2015 (in thousands):
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____________
(1)
The $1.2 million of accumulated net losses together with the accrued interest of $657 were recovered by Whiting in full during the third quarter of 2016, which interest is included in general and administrative expenses in the 2016 statement of distributable income.
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7. RELATED PARTY TRANSACTIONS
Plugging and Abandonment - During the years ended December 31, 2017, 2016 and 2015, Whiting incurred $0.7 million, $0.6 million and $0.1 million, respectively, of plugging and abandonment costs on the underlying properties. Pursuant to the terms of the conveyance agreement, plugging and abandonment costs relating to the underlying properties, net of any proceeds received from the salvage of equipment, are funded entirely by Whiting and are not therefore included as a deduction in the calculation of net proceeds or otherwise deducted from Trust unitholders over the term of the Trust.
Operating Overhead - Pursuant to the terms of its joint operating agreements, Whiting deducts from the gross oil and gas sales proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally, with respect to those underlying properties for which Whiting is the operator but where there is no operating agreement in place, Whiting deducts from the gross proceeds an overhead fee calculated in the same manner that Whiting allocates overhead to other similarly owned properties, which is customary practice in the oil and gas industry. Operating overhead activities include various engineering, legal, and administrative functions. The fee is adjusted annually pursuant to COPAS guidelines and will increase or decrease each year based on changes in the year-end index of average weekly earnings of crude petroleum and natural gas workers. The following table presents the Trust’s portion of these overhead charges for the distributions made during the years ended December 31, 2017, 2016 and 2015 (dollars in thousands, except monthly amounts per well):
			
		
			
		
Administrative Services Fee - Under the terms of the administrative services agreement, the Trust is obligated to pay a quarterly administration fee of $50,000 to Whiting 60 days following the end of each calendar quarter. General and administrative expenses in the Trust’s statements of distributable income for the years ended December 31, 2017, 2016 and 2015 includes $200,000 in each period for quarterly administrative fees paid to Whiting.
Trustee Administrative Fee - Under the terms of the Trust agreement, the Trust pays an annual administrative fee to the Trustee of $175,000, which is paid in four quarterly installments and is billed in arrears. Starting in 2017, such fee escalates by 2.5% each year and therefore, the annual administrative fee to be paid to the Trustee for 2017 services is $179,375, which was paid in four quarterly installments and billed in arrears. General and administrative expenses in the Trust’s statements of distributable income for the years ended December 31, 2017, 2016 and 2015 include $178,281, $175,000, $175,000, respectively, for administrative fees paid to the Trustee.
Letter of Credit - In June 2012, Whiting established a $1.0 million letter of credit for the Trustee in order to provide it with a mechanism to pay the operating expenses of the Trust, in the event that Whiting should fail to lend funds to the Trust, if requested to do so by the Trustee. This letter of credit will not be used to fund NPI distributions to unitholders, and if the Trustee were to draw on the letter of credit or were to borrow funds from Whiting or other entities, no further distributions would be made to unitholders until all such amounts, including interest thereon if applicable, have been repaid by the Trust.
Lending to the Trust -The Trustee can authorize the Trust to borrow money for the purpose of paying Trust administrative or incidental expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee, Whiting or the Delaware Trustee as a lender, provided that the terms of the loan are similar to the terms it would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself, which may be a non-interest bearing account, and make other short term investments with the funds distributed to the Trust. As of December 31, 2017 and 2016, the Trust had no borrowings outstanding.
8. SUBSEQUENT EVENTS
On March 1, 2018, a distribution of $0.171231 per Trust unit was paid to Trust unitholders of record on February 19, 2018. This aggregate distribution to all Trust unitholders consisted of net cash proceeds of $3.3 million paid by Whiting to the Trust, less a provision of $0.2 million for estimated Trust expenses and $4,715 for Montana state income tax withholdings.
			
		
			
		
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS RESERVE INFORMATION (UNAUDITED)
Oil and Gas Reserve Quantities
Estimates of proved reserves attributable to the Trust and the related valuations were based on reports prepared by the Trust’s independent petroleum engineers Cawley, Gillespie & Associates, Inc. Proved reserve estimates included herein conform to the definitions prescribed by the FASB and SEC. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price and cost changes and other factors.
As of December 31, 2017, all of the underlying properties’ oil and gas reserves are attributable to properties within the United States. Proved reserves attributable to the Trust and related standardized measure valuations are prepared on an accrual basis for all periods presented, which is the basis on which Whiting and the underlying properties maintain their production records and is different from the cash basis on which the Trust production records are maintained.
The following is a summary of the changes in quantities of proved oil and gas reserves attributable to the Trust for the years ended December 31, 2015, 2016 and 2017:
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____________
(1)
Reserves related to the underlying properties on a 100% full economic life basis as of January 1, 2015, December 31, 2015, 2016 and 2017 were 13.4 MMBOE, 8.9 MMBOE, 7.4 MMBOE and 7.9 MMBOE, respectively. The oil and gas reserve quantities presented in the tables above are on a 90% NPI Trust life basis.
(2)
The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021 or (2) the time when the Trust’s minimum volumes of 10.61 MMBOE have been produced and sold from the underlying properties, or (b) the sale of the net profits interest. The December 31, 2017 reserve report projects that the underlying properties will produce the Trust’s minimum volumes prior to December 31, 2021. Since the net profits interest is not expected to contractually terminate until December 31, 2021, the December 31, 2017 reserve report includes 417 MBOE of additional reserves attributable to the 90% NPI in excess of the Trust’s minimum volumes. The December 31, 2016 and 2015 reserve reports, however, projected
			
		
			
		
that the underlying properties would produce the Trust’s minimum volumes by July 31, 2023 and June 30, 2022, respectively, whereby the Trust would only be entitled to receive the minimum volumes of 10.61 MMBOE.
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Notable changes in proved reserves for the year ended December 31, 2017 included:
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·
Revisions to previous estimates. In 2017, revisions to previous estimates increased proved reserves by a net amount of 279 MBOE. Included in these revisions were (i) 418 MBOE of upward adjustments caused by higher oil and gas pricing incorporated into the Trust’s reserve estimates as of December 31, 2017 compared to December 31, 2016 and (ii) 139 MBOE of net downward adjustments attributable to reservoir analysis.
·
Extensions and discoveries. In 2017, total extensions and discoveries of 138 MBOE were attributable to successful drilling in the Keystone South field pursuant to a farm-out agreement.
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Notable changes in proved reserves for the year ended December 31, 2016 included:
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·
Revisions to previous estimates. In 2016, revisions to previous estimates increased proved reserves by a net amount of 2 MBOE. Included in these revisions were (i) 472 MBOE of net upward adjustments attributable to reservoir analysis and enhanced well performance and (ii) 470 MBOE of downward adjustments caused by lower oil and gas pricing incorporated into the Trust’s reserve estimates at December 31, 2016 as compared to December 31, 2015.
Notable changes in proved reserves for the year ended December 31, 2015 included:
·
Revisions to previous estimates. In 2015, revisions to previous estimates decreased proved reserves by a net amount of 493 MBOE. These revisions include a downward adjustment of 592 MBOE as a result of the December 31, 2015 reserve report projecting the net profits interest to terminate by June 30, 2022 as compared to the December 31, 2014 reserve report’s projected termination date of December 31, 2021. The extension of the expected termination date of the NPI was caused by lower oil and gas pricing incorporated into the Trust’s reserve estimates at December 31, 2015 as compared to December 31, 2014. This downward revision was partially offset, however, by an increase of 99 MBOE attributable to well performance.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure relating to proved oil and gas reserves and the changes in the standardized measure relating to proved oil and natural gas reserves were prepared in accordance with the provisions of FASB ASC Topic 932, Extractive Activities-Oil and Gas. Future cash inflows as of each period end were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended) to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming the continuation of existing economic conditions. The standardized measure of discounted future net cash flows has not been reduced by federal or state income taxes due to taxable income being passed through to the unitholders of the Trust.
The standardized measure relating to proved oil and gas reserves attributable to the Trust is as follows (in thousands):
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____________
(1)
No provision for federal or state income taxes has been provided because taxable income is passed through to the unitholders of the Trust.
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The changes in the standardized measure relating to proved oil and gas reserves attributable to the Trust are as follows (in thousands):
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Future cash inflows included in the standardized measure relating to proved oil and natural gas reserves incorporate weighted average sales prices (inclusive of adjustments for quality and location) as follows:
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SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
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____________
(1)
Dollars in thousands, except distributions per unit.
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Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by Whiting to The Bank of New York Mellon Trust Company, N.A., as Trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, the Trustee carried out an evaluation of the Trust’s disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.
Due to the contractual arrangements of (i) the Trust agreement and (ii) the conveyance of the NPI, the Trustee relies on (a) information provided by Whiting, including historical operating data, plans for future operating and capital expenditures, reserve information and information relating to projected production, and (b) conclusions and reports on oil and gas reserves by the Trust’s independent reserve engineers. Refer to the risk factors entitled “The Trust and the Trust unitholders have no voting or managerial rights with respect to the underlying properties. As a result, neither the Trust nor the unitholders have any ability to influence the operation of the underlying properties” and “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report on Form 10-K, for a description of certain risks relating to these arrangements and reliance on information when reported by Whiting to the Trustee and recorded in the Trust’s results of operations.
Changes in Internal Control over Financial Reporting. During the quarter ended December 31, 2017, there was no change in the Trust’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of Whiting.
Trustee’s Annual Report on Internal Control Over Financial Reporting. A registrant's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the modified cash basis of accounting. A registrant's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the registrant; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the modified cash basis of accounting, and that receipts and expenditures of the registrant are being made only in accordance with authorizations of the Trustee; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the registrant’s assets that could have a material effect on the financial statements.
The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Exchange Act. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with the modified cash basis of accounting.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Trustee conducted an evaluation of the effectiveness of the Trust's internal control over financial reporting based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee's evaluation under the framework in Internal Control-Integrated Framework (2013), the Trustee concluded that the Trust's internal control over financial reporting was effective as of December 31, 2017.
			
		
			
		
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
The Trust has no directors or executive officers. The Trustee is a corporate trustee that may be removed by the affirmative vote of the holders of not less than a majority of the outstanding Trust units at a meeting at which a quorum is present.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires the holders of more than 10 percent of the Trust units to file with the SEC reports regarding their ownership and changes in ownership of the Trust units. Based solely on a review of these reports and any such reports furnished to the Trustee, the Trustee is not aware of any 10 percent unitholder having failed to comply with all Section 16(a) filing requirements in 2017.
Audit Committee and Nominating Committee
Because the Trust does not have a board of directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.
Code of Ethics
The Trust does not have a principal executive officer, principal financial officer, principal accounting officer or controller and, therefore, has not adopted a code of ethics applicable to such persons. However, employees of the Trustee must comply with The Bank of New York Mellon Trust Company’s code of ethics.
Item 11.
Item 11. Executive Compensation
During the year ended December 31, 2017, the Trustee received administrative fees from the Trust in the amount of $178,281. The Trust does not have any executive officers, directors or employees. Because the Trust does not have a board of directors, it does not have a compensation committee.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
(a) Security Ownership of Certain Beneficial Owners.
Based on a review of SEC filings, the Trustee is not aware of any holders of 5% or more of the units.
(b) Security Ownership of Management.
Not applicable.
(c) Changes in Control.
The registrant knows of no arrangement, including any pledge by any person of securities of the registrant or any of its parents, the operation of which may at a subsequent date result in a change of control of the registrant.
			
		
			
		
Item 13.
Item 13. Certain Relationships, Related Transactions and Director Independence
Letter of Credit
In June 2012, Whiting established a $1.0 million letter of credit for the Trustee in order to provide it with a mechanism to pay the operating expenses of the Trust, in the event that Whiting should fail to lend funds to the Trust, if requested to do so by the Trustee. This letter of credit will not be used to fund NPI distributions to unitholders, and if the Trustee were to draw on the letter of credit or were to borrow funds from Whiting or other entities, no further distributions would be made to the unitholders until all such amounts including interest therein, if applicable, have been repaid by the Trust.
Plugging and Abandonment
During the year ended December 31, 2017, Whiting incurred $0.7 million of plugging and abandonment costs on the underlying properties. Pursuant to the terms of the conveyance agreement, plugging and abandonment charges relating to the underlying properties, net of any proceeds received from the salvage of equipment, are funded entirely by Whiting and are not therefore included as a deduction in the calculation of net proceeds or otherwise deducted from Trust unitholders over the term of the Trust.
Operating Overhead
Pursuant to the terms of its joint operating agreements, Whiting deducts from the gross oil and gas sales proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally, with respect to those underlying properties for which Whiting is the operator but where there is no operating agreement in place, Whiting deducts from the gross proceeds an overhead fee calculated in the same manner that Whiting allocates overhead to other similarly owned properties, which is customary practice in the oil and gas industry. Operating overhead activities include various engineering, legal, and administrative functions. For the year ended December 31, 2017, the Trust’s portion of the monthly charge totaled $1.4 million and averaged $372 per month per active operated well. The fee is adjusted annually pursuant to COPAS guidelines and will increase or decrease each year based on changes in the year-end index of average weekly earnings of crude petroleum and natural gas workers.
Administrative Services
Under the terms of the administrative services agreement, the Trust pays a quarterly administration fee of $50,000 to Whiting 60 days following the end of each calendar quarter. General and administrative expenses in the Trust’s statements of distributable income for the year ended December 31, 2017 include $200,000 for quarterly administrative fees paid to Whiting.
The administrative services agreement will expire upon the termination of the net profits interest unless earlier terminated by mutual agreement of the Trustee and Whiting.
Trustee Administration Fee
Under the terms of the Trust agreement, the Trust pays an annual administrative fee to the Trustee of $175,000, which is paid in four quarterly installments and is billed in arrears. Starting in 2017, such fee escalates by 2.5% each year and therefore, the annual administrative fee to be paid to the Trustee for 2017 services is $179,375, which was paid in four quarterly installments and billed in arrears. General and administrative expenses in the Trust’s statements of distributable income for the year ended December 31, 2017 include $178,281 for quarterly administrative fees paid to the Trustee.
Director Independence
The Trust does not have a board of directors and therefore no determination been made relative to director independence.
Item 14.
Item 14. Principal Accounting Fees and Services
The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustee. The Trustee has appointed Deloitte & Touche, LLP (“Deloitte”) as the independent registered public accounting firm to audit the Trust’s financial statements for the fiscal year ending December 31, 2018. During fiscal 2017, Deloitte served as the Trust’s independent registered public accounting firm.
			
		
			
		
The following table presents the aggregate fees billed to the Trust for the fiscal years ended December 31, 2017 and 2016 by Deloitte:
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____________
(1)
Fees for audit services in 2017 and 2016 consisted of the audit of the Trust’s annual financial statements and reviews of the Trust’s quarterly financial statements.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a)(1) Financial Statements
Refer to the Index to Whiting USA Trust II Financial Statements included in Item 8 of this Annual Report on Form 10-K for a list of all financial statements filed as part of this report.
(a)(2) Schedules
Schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.
(a)(3) Exhibits
See Exhibit Index.
Item 16. Form 10-K Summary
None.
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EXHIBIT INDEX
____________
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(* Asterisk indicates exhibit previously filed with the SEC and incorporated herein by reference.)
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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﻿
						
Whiting USA Trust II
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﻿
By:
The Bank of New York Mellon Trust Company, N.A.,
﻿
						
as Trustee
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﻿
By:
/s/ Mike Ulrich
﻿
						
Mike Ulrich
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Vice President
﻿
						
						
March 22, 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.
			
		
			
		
			
		
			
		
			
		
Appendix 1
Cawley, Gillespie & Associates, Inc.
PETROLEUM CONSULTANTS
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﻿
						
						
13640 BRIARWICK DRIVE, SUITE 100
306 WEST SEVENTH STREET, SUITE 302
1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1707
FORT WORTH, TEXAS 76102-4987
HOUSTON, TEXAS 77002-5008
512-249-7000
817-336-2461
713-651-9944
﻿
www.cgaus.com
						
﻿
January 9, 2018
The Bank of New York Mellon Trust Company, N.A.
As Trustee of Whiting USA Trust II
601 Travis Street, 16th Floor
Houston, Texas 77002
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﻿
Re:
Evaluation Summary - SEC Price
﻿
						
Whiting USA Trust II Underlying Properties
﻿
						
Total Proved Reserves
﻿
						
Certain Properties Located in Various States
﻿
						
As of December 31, 2017
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﻿
						
Pursuant to the Guidelines of the Securities and
﻿
						
Exchange Commission for Reporting Corporate
﻿
						
Reserves and Future Net Revenue
Gentlemen:
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We are submitting our estimates of total proved reserves and forecasts of economics attributable to the underlying properties, from which a net profits interest has been formed and conveyed by Whiting Petroleum Corporation to the Whiting USA Trust II. These oil and gas properties are located in Arkansas, Colorado, Michigan, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas, and Wyoming and this report has been prepared for the Trustee of Whiting USA Trust II based on its request. Included in the tables below are the total proved reserves attributable to (i) the same underlying properties through their full economic life and (ii) the same underlying properties but only the reserves estimated to be produced by December 31, 2021, which is the estimated termination date for Whiting USA Trust II. This report, completed January 9, 2018 was prepared for the purpose of public disclosure by Whiting in filings made with the U.S. Securities and Exchange Commission (“SEC”) in accordance with the disclosure requirements set forth in SEC regulations, and it includes results for an SEC pricing scenario accordingly. It covers 100% of the total proved reserves estimated for Whiting USA Trust II. The results of this evaluation are presented in the two tables immediately below as follows:
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*Calculated based on an energy equivalent that one Bbl of crude oil equals six Mcf of natural gas and one Bbl of crude oil equals one Bbl of natural gas liquids.
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The discounted cash flow value shown in the previous two tables should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc.
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Hydrocarbon Pricing
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In accordance with SEC guidelines, hydrocarbon prices used in the preparation of this report have been determined as an unweighted arithmetic average of the first-day-of-the-month price for each month of 2017, unless prices were otherwise defined by contractual arrangements. Accordingly, NYMEX Oil and Henry Hub Gas prices of $51.34 per bbl and $2.98 per MMBtu, respectively, were used as of December 31, 2017. Further adjustments were applied on a lease level basis for oil price differentials, gas price differentials and heating values as furnished by your office. Prices were not escalated in the SEC scenario. The average adjusted prices used in the estimation of proved reserves for the underlying properties full economic life were $46.06 per bbl of oil, $31.65 per bbl of natural gas liquids and $3.19 per mcf of natural gas. For the proved reserves of the underlying properties estimated to be produced by December 31, 2021, the average adjusted prices were $45.70 per bbl of oil, $31.08 per bbl of natural gas liquids and $3.16 per mcf of natural gas.
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Capital, Expenses and Taxes
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Capital expenditures, lease operating expenses and ad valorem tax values were forecast as provided by your office. As you explained, the capital costs were based on the most current estimates, lease operating expenses were based on the analysis of historical actual expenses, operating overhead is included for both operated and non-operated properties. Capital costs and lease operating expenses were held constant in accordance with SEC guidelines. State severance tax rates were applied at current statutory percentages of oil and gas revenue, incorporating certain severance tax incentives and allowances for limited time periods where allowable in Whiting’s various tax jurisdictions.
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SEC Conformance and Regulations
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The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 2 and 3 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
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Reserve Estimation Methods
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The methods employed in estimating reserves are described on page 1 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. All reserve estimates involve an assessment of the uncertainty relating to the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends mainly on the amount of the reliable geologic and engineering data available at the time of the estimate and the interpretation of such data, as well as the inherent uncertainties attributable to variations in reservoir and rock quality, offset drainage, mechanical wellbore integrity among others. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. This report addresses only the proved reserves attributable to the properties evaluated herein.
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Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.
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Miscellaneous
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An on-site field inspection of the properties has not been performed. The mechanical operation or conditions of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The costs of plugging and abandonment, less proceeds from the salvage value of equipment and/or facilities, have been included where material.
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The reserve estimates were based on interpretations of factual data furnished by your office. We have used all methods and procedures as we considered necessary under the circumstances to prepare the report. We believe that the assumptions, data, methods and procedures were appropriate for the purpose served by this report. Production data, gas prices, gas price differentials, expense data, tax values and ownership interests were also supplied by you and were accepted as furnished. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data.
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The professional qualifications of the undersigned, the technical personnel primarily responsible for the preparation of this report, are included as an attachment to this letter.
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﻿
﻿
Yours very truly,
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﻿
﻿
﻿
W. Todd Brooker, P. E.
President
Cawley, Gillespie & Associates
Texas Registered Engineering Firm
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﻿
			 		
			
		
			
		
			
		
			
		
			
		
APPENDIX
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Methods Employed in the Estimation of Reserves
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﻿
﻿
﻿
The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.
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Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.
﻿
A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:
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Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.
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Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.
Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy, but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.
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Analogy. This method, which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. The analogy method may also be applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained in this manner are generally considered to have a relatively low degree of accuracy.
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Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates contain inherent uncertainties and are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.
			
		
						
						
						
						
Cawley, Gillespie & Associates, Inc.
Appendix
			
		
			
		
			
		
			
		
APPENDIX
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Reserve Definitions and Classifications
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﻿
﻿
The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:
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"(22)Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations- prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
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"(i)The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
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"(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
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"(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
﻿
"(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
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"(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
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"(6)Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
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“(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
﻿
“(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
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"(31)Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
﻿
“(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
﻿
“(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
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“(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir (as defined in Subpart 1200 of SEC Regulation S-K) or by other evidence using reliable technology establishing reasonable certainty.
			 		
"(26)Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
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“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”
			
		
						
						
						
						
Cawley, Gillespie & Associates, Inc.
Appendix
			
		
			
		
			
		
			
		
﻿
Cawley, Gillespie & Associates, Inc.
PETROLEUM CONSULTANTS
﻿
﻿
						
						
13640 BRIARWICK DRIVE, SUITE 100
306 WEST SEVENTH STREET, SUITE 302
1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1707
FORT WORTH, TEXAS 76102-4987
HOUSTON, TEXAS 77002-5008
512-249-7000
817-336-2461
713-651-9944
﻿
www.cgaus.com
						
﻿
Professional Qualifications of W. Todd Brooker, P.E.
President of Cawley, Gillespie & Associates
﻿
Mr. Brooker has been a Petroleum Consultant for Cawley, Gillespie & Associates (CG&A) since 1992, and became President in 2017. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures. Prior to CG&A he worked in Gulf of Mexico drilling and production engineering at Chevron USA. Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering. He is a registered professional engineer in Texas, No. 83462, and a member of the Society of Petroleum Engineers (SPE).
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