Act, as amended (the “CAA”), including rules that limit emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHGs emission standards trigger the CAA construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards took effect in January 2011. In June 2010, the EPA also 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 becoming subject to permitting. Further, facilities required to obtain PSD permits for their GHG emissions are required to reduce those emissions consistent with guidance for determining “best available control technology” standards for GHG, which guidance was published by the EPA in November 2010. Also in November 2010, the EPA expanded its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis. Whiting believes that it is in compliance with all substantial applicable emissions requirements.
In June 2014, the Supreme Court upheld most of the EPA’s GHGs permitting requirements, allowing the agency to regulate the emission of GHGs from stationary sources already subject to the PSD and Title V requirements. Certain of Whiting’s equipment and installations may currently be subject to PSD and Title V requirements and hence, under the Supreme Court’s ruling, may also be subject to the installation of controls to capture GHGs. For any equipment or installation so subject, Whiting may have to incur increased compliance costs to capture related GHGs emissions, which could reduce cash distributions by the Trust and the value of Trust units.
In October 2016, the EPA proposed revisions to the rule applicable to GHGs for PSD and Title V permitting requirements. 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 air permitting requirements, has not yet been finalized.
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. On March 28, 2017, the Trump Administration issued an executive order directing the EPA to review the Clean Power Plan. On October 16, 2017, the EPA published a proposed rule that would repeal the Clean Power Plan. On August 18, 2018, the EPA proposed the Affordable Clean Energy (“ACE”) rule as a replacement to the Clean Power Plan. The ACE rule was published in the
Federal Register
on August 31, 2018, and comments were accepted until October 31, 2018. The EPA has not yet issued a final ACE rule, although several states have announced their intention to challenge the rule once it is made final.
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 has issued the Subpart OOOOa regulations that limit emissions of GHGs associated with the operations of the underlying properties, which will require Whiting to incur costs to inventory and reduce emissions of GHGs associated with the operations of the underlying properties and that could adversely affect demand for the oil, natural gas liquids and natural gas produced. Finally, it should be noted that many scientists have concluded that increasing concentrations of GHGs in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events.
Air Emissions.
The CAA and comparable state laws regulate emissions of various air pollutants from various industrial sources through air emissions permitting programs and also impose other monitoring and reporting requirements. Operators of the underlying properties, including Whiting, may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining pre‑construction and operating permits and approvals for air emissions. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. For example, in 2012, the EPA finalized rules establishing new air emission controls for oil and natural gas production operations. Specifically, the EPA’s rule includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and
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 and sanctions, in oil‑producing countries or affecting other oil‑producing activity, such as the U.S. imposed sanctions on Venezuela and Iran and conflicts in the Middle East;
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developments of United States energy infrastructure;
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the level of global oil and natural gas exploration and production activity;
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proximity and capacity of oil and natural gas pipelines and other transportation facilities;
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the effects of global and domestic credit, financial and economic issues;
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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 expected from the current U.S. administration;
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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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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 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 and are traded on the OTC market. It will likely be more difficult for unitholders to sell the Trust units or to obtain accurate quotations of the Trust units.
The Trust units ceased trading on the NYSE on January 6, 2016 and transitioned to the OTC market, operated by OTC Markets Group, effective with the opening of trading on January 7, 2016 under the trading symbol “WHZT.” The Trust can provide no assurance that any trading market for the Trust units will exist on the OTC or that current trading levels will be sustained or not diminish. Securities traded on the over‑the‑counter markets are typically less liquid than stocks that trade on the NYSE. Trading on the over‑the‑counter market may negatively affect the trading price and liquidity of the Trust units and could result in larger spreads in the bid and ask prices for Trust units. Unitholders may find it difficult to resell their Trust units due to the delisting.
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 11.1% for oil and 23.0% for gas between 2019 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, 2018, the percentage of remaining reserves expected to be produced during the term of the NPI was 29.4%. 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 $65.56 per Bbl and $3.10 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, 2018, pursuant to current SEC and FASB guidelines.
Financial returns to purchasers of Trust units will vary in part based on how quickly 11.79 MMBOE are produced from the underlying properties and sold, and it is not known when that will occur.
The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold, or (b) the sale of the net profits interest. The reserve report currently projects that 11.79 MMBOE will be produced from the underlying properties prior to December 31, 2021. As basis for comparison, the estimated date when such amount would have been produced according to the 2016 year‑end reserve report was July 31, 2023. However, the exact rate of production cannot be predicted with certainty and such amount may be produced before or after that date. If production attributable to the underlying properties is slower than estimated, then financial returns to purchasers of Trust units will be lower (assuming constant prices) because cash distributions attributable to such production will occur at a later date.
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. The Trust does not maintain any type of insurance against any of the risks of conducting oil and gas exploration and production, hydraulic fracturing operations or related activities.
Also, Whiting’s oil, natural gas liquids and natural gas production depends in large part on the proximity 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 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, 2018.
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 55% of the underlying properties based on the standardized measure of discounted future net cash flows at December 31, 2018. However, for the 45% 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 CO
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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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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 rock 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.
In addition to the EPA, other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy, the U.S. Government Accountability Office, the U.S. Department of Interior and the White House Council for Environmental Quality.
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. 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. In 2018, Colorado considered, but did not adopt, Proposition 112, a ballot measure that would have established a 2,500-foot setback for oil and gas operations from certain areas. 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 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, as recently occurred when a significant increase in differential for certain properties located in Wyoming and Texas impacted the February 2019 distribution.
The Trust units may lose value as a result of title deficiencies with respect to the underlying properties.
The existence of a material title deficiency with respect to the underlying properties could reduce the value of a property or render it worthless, thus adversely affecting the NPI and distributions to Trust unitholders. Whiting does not obtain title insurance covering mineral leaseholds, and Whiting’s failure to cure any title defects may cause Whiting to lose its rights to production from the underlying properties. In the event of any such material title problem, proceeds available for distribution to Trust unitholders and the value of the Trust units may be reduced.
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.
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The Trust has no employees and is reliant on Whiting’s employees to operate those underlying properties for which Whiting is designated as the operator. Whiting’s employees are also responsible for the operation of other oil and gas properties Whiting owns, which may require a significant portion or all of their time and resources.
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The documents governing the Trust generally do not provide a mechanism for resolving these conflicting interests.
The Trust is managed by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.
The business and affairs of the Trust are 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.
Under certain circumstances, the Trust provides that the Trustee may be required to sell the NPI and dissolve the Trust prior to the expected termination of the Trust. As a result, Trust unitholders may not recover their investment.
The Trust is required to sell the NPI and liquidate if cash proceeds to the Trust from the net profits interest are less than $2.0 million for each of any two consecutive years. During the years ended December 31, 2018, 2017 and 2016, the Trust received cash proceeds of $18.9 million, $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.
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 Subpart OOOOa requirements that the oil and gas industry reduce emissions of greenhouse gases
and to cover additional equipment and activities in the oil and gas production chain. The final rule sets emissions limits for methane, which is the principal greenhouse gas emitted by equipment and processes in the oil and gas sector. This rule applies to new, reconstructed and modified processes and equipment.
In accordance with President Obama’s Climate Action Plan, in August 2015, the EPA issued a rule to reduce carbon emissions from electric generating units. The rule, commonly called the “Clean Power Plan,” requires states to develop plans to reduce carbon emissions from fossil fuel‑fired generating units commencing in 2022, with the reductions to be fully phased in by 2030. Each state is given a different carbon reduction target, but the EPA expects that, in the aggregate, the overall proposal will reduce carbon emissions from electric generating units by 32% from 2005 levels. States are given substantial flexibility in meeting their emission reduction targets and can generally choose to lower carbon emissions by replacing higher carbon generation, such as coal or natural gas, with lower carbon generation, such as efficient natural gas units or renewable energy alternatives. Several industry groups and states have challenged the Clean Power Plan in the Court of Appeals for the D.C. Circuit, and in February 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan while it is being challenged in court. On March 28, 2017, the Trump Administration issued an executive order directing the EPA to review the Clean Power Plan. On October 16, 2017, the EPA published a proposed rule that would repeal the Clean Power Plan. On August 18, 2018, EPA proposed the Affordable Clean Energy (ACE) rule as a replacement to the Clean Power Plan. The ACE rule was published in the Federal Register on August 31, 2018, and comments were accepted until October 31, 2018. The EPA has not yet issued a final ACE rule, although several states have announced their intention to challenge the rule once it is made final
.
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 has issued the Subpart OOOOa regulations that limit emissions of GHGs associated with the operations of the underlying properties, which will require Whiting to incur costs to inventory and reduce emissions of GHGs associated with the operations of the underlying properties and that could adversely affect demand for oil, natural gas liquids and natural gas produced. Finally, it should be noted that many scientists have concluded that increasing concentrations of GHGs in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on the Trust’s assets and the amount of cash available for distribution to the Trust unitholders.
Shortages or increases in costs of oil field equipment, services, qualified personnel and supply materials could delay production, thereby reducing the amount of cash available for distribution.
The demand for qualified and experienced field personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs, completion crews and other 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 CO
2
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.
If the financial position of Whiting degrades in the future, Whiting may not be able to satisfy its obligations to the Trust.
Whiting operates approximately 55% of the underlying properties based on the standardized measure of discounted future net cash flows at December 31, 2018. 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.
Whiting previously participated in the formation and initial public offering of Whiting USA Trust I (“Trust I”) on April 30, 2008 and Trust I terminated its NPI effective January 28, 2015 as a result of the contractual volumes being produced and sold from Trust I’s underlying properties. Given the differences in assets comprising the underlying properties, commodity prices, production and development costs, development schedule, operators of the underlying properties and regulatory environment, among other things, the historical results of operations of Trust I should not be relied on as an indicator of how Whiting USA Trust II will perform.
Under certain circumstances, the Trust provides that the Trustee may be required to reconvey to Whiting a portion of the NPI, which may impact how quickly 11.79 MMBOE are produced from the underlying properties for purposes of the NPI.
If Whiting is notified by a person with whom Whiting is a party to a contract containing a prior reversionary interest that Whiting is required to convey any of the underlying properties to such person or cease production from any well, then Whiting may provide such conveyance with respect to such underlying property or permanently cease production from such well. Such a reversionary interest typically results from the provisions of a joint operating agreement that governs the drilling of wells on jointly owned property and financial arrangements for instances where all owners may not want to make the capital expenditure necessary to drill a new well. The reversionary interest is created because an owner that does not consent to capital expenditures will not have to pay its share of the capital expenditure, but instead will relinquish its share of proceeds from the well until the consenting owners receive payout (or a multiple of payout) of their capital expenditures. In such case, Whiting may request the Trustee to reconvey to Whiting the NPI with respect to any such underlying property or well. The Trust will not receive consideration for any such reconveyance of a portion of the NPI and, any such reconveyance of a portion of the NPI may extend the time it takes 11.79 MMBOE (10.61 MMBOE at the 90% NPI) to be produced from the underlying properties for purposes of the NPI.
Whiting depends on computer and telecommunications systems, and failures in its systems or cyber security attacks could significantly disrupt its business operations.
Whiting has entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with its business. In addition, Whiting has developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. It is possible that Whiting, or these third parties, could incur interruptions from cyber security attacks, computer viruses or malware, or that third party service providers could cause a breach of Whiting’s data. Whiting believes that it has positive relations with its related vendors and maintains adequate anti-virus and malware software and controls; however, any interruptions to Whiting’s arrangements with third parties for its computing and communications infrastructure or any other interruptions to, or breaches of, its information systems could lead to data corruption, communication interruption, loss of sensitive or confidential information or otherwise significantly disrupt Whiting’s business operations. Although Whiting utilizes various procedures and controls to monitor these threats and mitigate its exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. To Whiting’s knowledge, Whiting has not experienced any material losses relating to cyber attacks; however, there can be no assurance that Whiting will not suffer material losses in the future either as a result of an interruption to or a breach of its systems or those of its third party vendors and service providers, and any such interruption or breach could have a material adverse effect on the Trust.
Cyber attacks or other failures in telecommunications or information technology systems could result in information theft, data corruption and significant disruption of the Trustee’s operations.
The Trustee depends heavily upon information technology systems and networks in connection with its business activities. Despite a variety of security measures implemented by the Trustee, events such as the loss or theft of back-up tapes or other data storage media could occur, and the Trustee’s computer systems could be subject to physical and electronic break-ins, cyber attacks and similar disruptions from unauthorized tampering, including threats that may come from external factors, such as governments, organized crime, hackers and third parties to whom certain functions are outsourced, or may originate internally from within the respective companies.
If a cyber attack were to occur, it could potentially jeopardize the confidential, proprietary and other information processed and stored in, and transmitted through, the Trustee’s computer systems and networks, or otherwise cause interruptions or malfunctions in the operations of the Trust, which could result in litigation, increased costs and regulatory penalties. Although steps are taken to prevent and detect such attacks, it is possible that a cyber incident will not be discovered for some time after it occurs, which could increase exposure to these consequences.
The Trust has not requested a ruling from the IRS regarding the tax treatment of ownership of the Trust units. If the IRS were to determine (and be sustained in that determination) that the Trust is not a “grantor trust” for federal income tax purposes, or that the NPI is not properly treated as a production payment (and thus could fail to qualify as a debt instrument) for federal income tax purposes, the Trust unitholders may receive different and potentially less advantageous tax treatment than they anticipated.
If the Trust were not treated as a grantor trust for federal income tax purposes, the Trust should be treated as a partnership for such purposes. Although the Trust would not become subject to federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the Trust unitholders, the Trust’s tax reporting requirements would be more complex and costly to implement and maintain, and its distributions to unitholders could be reduced as a result.
If the NPI were not treated as a debt instrument, any deductions allowed to an individual Trust unitholder in their recovery of basis in the NPI may be itemized deductions, the deductibility of which would be subject to limitations that may or may not apply depending upon the unitholder’s circumstances.
Neither Whiting nor the Trustee has requested a ruling from the IRS regarding these tax questions, and neither Whiting nor the Trust can assure that such a ruling would be granted if requested or that the IRS will not challenge this position on audit.
Thus, no assurance can be provided that the opinions and statements set forth in the discussion of U.S. federal income tax consequences would be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the Trust units and the prices at which Trust units trade. In addition, the costs of any contest with the IRS (whether or not such challenge is successful), principally legal, accounting and related fees, will result in a reduction in cash available for distribution to the Trust unitholders, and thus will be borne indirectly by the Trust unitholders.
Trust unitholders should be aware of the possible state tax implications of owning Trust units, and should consult their own tax advisors for advice regarding the state as well as federal tax implications of owning Trust units.
The Trust allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record ownership of the Trust units on the quarterly record date, instead of on the basis of the date a particular Trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the Trust unitholders.
The Trust generally allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record ownership of the Trust units on the quarterly record date, instead of on the basis of the date a particular Trust unit is transferred. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the Trust should be determined and allocated on a daily, prorated or other basis, which could require adjustments to the tax returns of the Trust unitholders affected by the issue and result in an increase in the administrative expense of the Trust in subsequent periods.
The tax treatment of an investment in Trust units could be affected by future legislative, judicial or administrative changes and differing opinions, possibly on a retroactive basis.
The U.S. federal income tax treatment of an investment in the Trust may be modified by administrative or legislative changes, or by judicial interpretation, at any time, possibly on a retroactive basis.
Trust unitholders will be required to pay taxes on their share of the Trust’s income even if they do not receive any cash distributions from the Trust.
For income tax purposes, Trust unitholders are treated as if they own the Trust’s taxable asset (which for tax purposes, is a loan receivable owed to the Trust from Whiting) and they receive the Trust’s income and are directly taxable thereon as if no trust were in existence. The Trust unitholders generally do not receive cash distributions from the Trust equal to their share of the Trust’s taxable income or even equal to the actual tax liability that results from that income. Because the Trust typically generates taxable income that is different in amount than the cash the Trust distributes, the Trust unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of the Trust’s taxable income even if they receive no cash distributions from the Trust.
Item 1B.
Unresolved Staff Comments
None.
Item 2.
Properties
Description of the Underlying Properties
The underlying properties consist of Whiting’s net interests in certain oil and natural gas producing properties as of the date of the conveyance of the NPI to the Trust, which properties are located primarily in the Permian Basin, Rocky Mountains, Gulf Coast and Mid‑Continent regions of the United States. The underlying properties include interests in 1,303 gross (367.8 net) producing oil and natural gas wells located in 46 predominately mature fields with established production profiles in 10 states. As of December 31, 2018, 100% of estimated proved reserves attributable to the Trust were classified as proved developed producing. For the year ended December 31, 2018, the net production attributable to the underlying properties was 1,137 MBOE or 3,115 BOE/d. Whiting operates approximately 55% of the underlying properties based on the December 31, 2018 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, 2018, on a cumulative accrual basis 8.97 MMBOE (85%) of the 10.61 MMBOE attributable to the NPI have been produced and sold or divested. The remaining minimum reserve balance of 1.63 MMBOE (at the 90% NPI) is projected to be produced prior to December 31, 2021, based on the Trust’s year‑end 2018 reserve report. Accordingly, the Trust’s remaining reserves attributable to the 90% NPI were estimated to be 2.44 MMBOE as of December 31, 2018, 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 11.1% for oil and 23.0% for gas from 2019 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, 2018, 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, 2018
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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|
|
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|
|
|
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Whiting USA Trust II
(4)
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Underlying Properties
(5)
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|
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(90% NPI through December 2021)
(6)
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(100% Full Economic Life)
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Oil
(7)
(MBbl)
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Natural Gas
(Mcf)
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MBOE
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Oil
(7)
(MBbl)
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Natural Gas
(Mcf)
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MBOE
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Proved reserves
(1)
:
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|
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|
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Developed
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2,084
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|
2,109
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|
|
2,435
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|
8,036
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|
7,055
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|
|
9,212
|
Undeveloped
(2)
|
|
-
|
|
-
|
|
|
-
|
|
-
|
|
-
|
|
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-
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Total proved—December 31, 2018
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2,084
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|
2,109
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|
|
2,435
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|
8,036
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|
7,055
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|
|
9,212
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|
|
|
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Standardized measure
(3)
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$
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45,548
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$
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101,358
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____________
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(1)
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Oil and gas reserve quantities have been derived from NYMEX oil and gas prices of $65.56 per Bbl and $3.10 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, 2018, pursuant to current SEC and FASB guidelines. The average NYMEX oil and gas prices for the month of January 2019 were $51.55 per Bbl and $3.23 per MMBtu, respectively.
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(2)
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This table does not include any proved undeveloped reserve quantities as of December 31, 2018 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, 2018 reserve report because no future capital has been committed for the development of such reserves on the underlying properties.
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(3)
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Standardized measure of discounted future net cash flows as of December 31, 2018. 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.
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|
(4)
|
|
The Trust’s estimated proved reserves as of December 31, 2018 on a 90% NPI basis were 2,435 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.
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(5)
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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.
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(6)
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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 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, 2018 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, 2018 reserve report includes 802 MBOE of additional reserves attributable to the 90% NPI in excess of the Trust’s minimum volumes.
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|
(7)
|
|
Oil includes natural gas liquids.
|
Proved reserves.
Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. Oil and gas reserve quantities and related discounted future net cash flows have been derived from oil and gas prices calculated using an average of the first‑day‑of‑the month price for each month of 2018, 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, 2018. 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, 2018 to December 31, 2018, 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 2018, revisions to previous estimates increased proved reserves by a net amount of 225 MBOE. Included in these revisions were (i) 338 MBOE of upward adjustments caused by higher oil and gas pricing incorporated into the Trust’s reserve estimates as of December 31, 2018 compared to December 31, 2017 and (ii) 113 MBOE of net downward adjustments attributable to reservoir analysis. In addition, total extensions and discoveries of 149 MBOE in 2018 were attributable to successful drilling in the Keystone South field pursuant to a farm-out agreement.
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. The Trust’s primary contact at CG&A is Mr. W. Todd Brooker, President. Mr. Brooker is a State of Texas Licensed Professional Engineer. Refer to Appendix 1 and Exhibit 99 of this Annual Report on Form 10‑K for the Report of Cawley, Gillespie & Associates, Inc. and further information regarding the professional qualifications of Mr. Brooker.
Whiting’s Senior Vice President of Planning and Reservoir Engineering is responsible for overseeing the preparation of the reserves estimates. He has over 37 years of experience including reservoir engineering and reserve estimation, and he holds a Bachelor of Science degree in petroleum engineering from the Colorado School of Mines. He is a registered Professional Engineer and 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, 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total Acreage
|
Region
|
|
Fields
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
Permian Basin
|
|
17
|
|
24,470
|
|
19,416
|
|
5,434
|
|
3,416
|
|
29,904
|
|
22,832
|
Rocky Mountains
|
|
14
|
|
24,903
|
|
10,162
|
|
-
|
|
-
|
|
24,903
|
|
10,162
|
Gulf Coast
|
|
8
|
|
10,412
|
|
3,968
|
|
470
|
|
153
|
|
10,882
|
|
4,121
|
Mid
-
Continent
|
|
7
|
|
2,367
|
|
1,219
|
|
40
|
|
34
|
|
2,407
|
|
1,253
|
Total
|
|
46
|
|
62,152
|
|
34,765
|
|
5,944
|
|
3,603
|
|
68,096
|
|
38,368
|
The following is a summary of the producing wells on the underlying properties as of December 31, 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated Wells
|
|
Non
-
Operated Wells
|
|
Total Wells
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
Oil
|
|
273
|
|
246.0
|
|
955
|
|
92.0
|
|
1,228
|
|
338.0
|
Natural gas
|
|
30
|
|
25.4
|
|
45
|
|
4.4
|
|
75
|
|
29.8
|
Total
|
|
303
|
|
271.4
|
|
1,000
|
|
96.4
|
|
1,303
|
|
367.8
|
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, 2018, 2017 and 2016. 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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|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
Developmental
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil wells
(1)
|
|
2
|
|
0.50
|
|
2
|
|
0.50
|
|
3
|
|
0.02
|
Natural gas wells
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
Exploratory
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil wells
|
|
-
|
|
-
|
|
1
|
|
0.25
|
|
-
|
|
-
|
Natural gas wells
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
Total
|
|
2
|
|
0.50
|
|
3
|
|
0.75
|
|
3
|
|
0.02
|
____________
|
(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.
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|
(2)
|
|
No exploratory wells were in process of being drilled as of December 31, 2018 and 2017. 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.
|
As of December 31, 2018, no wells were in the process of being drilled or completed.
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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|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
Net sales volumes:
|
|
|
|
|
|
|
|
|
|
Oil production (MBbl)
(1)
|
|
|
936
|
|
|
964
|
|
|
1,002
|
Natural gas production (MMcf)
|
|
|
1,206
|
|
|
1,220
|
|
|
1,397
|
Total production (MBOE)
|
|
|
1,137
|
|
|
1,168
|
|
|
1,235
|
Average daily production (MBOE/d)
|
|
|
3.1
|
|
|
3.2
|
|
|
3.4
|
Garland field sales volumes
(2)
:
|
|
|
|
|
|
|
|
|
|
Oil production (MBbl)
(1)
|
|
|
147
|
|
|
152
|
|
|
154
|
Natural gas production (MMcf)
|
|
|
40
|
|
|
41
|
|
|
47
|
Total production (MBOE)
|
|
|
154
|
|
|
159
|
|
|
162
|
Keystone field sales volumes
(2)
:
|
|
|
|
|
|
|
|
|
|
Oil production (MBbl)
(1)
|
|
|
148
|
|
|
139
|
|
|
98
|
Natural gas production (MMcf)
|
|
|
384
|
|
|
310
|
|
|
289
|
Total production (MBOE)
|
|
|
212
|
|
|
190
|
|
|
146
|
Rangely field sales volumes
(2)
:
|
|
|
|
|
|
|
|
|
|
Oil production (MBbl)
(1)
|
|
|
149
|
|
|
149
|
|
|
162
|
Natural gas production (MMcf)
|
|
|
-
|
|
|
-
|
|
|
-
|
Total production (MBOE)
|
|
|
149
|
|
|
149
|
|
|
162
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
(1)
|
|
$
|
53.91
|
|
$
|
44.35
|
|
$
|
35.22
|
Natural gas (per Mcf)
|
|
$
|
3.40
|
|
$
|
3.26
|
|
$
|
2.48
|
Average production costs:
|
|
|
|
|
|
|
|
|
|
Production costs per BOE
(3)
|
|
$
|
24.65
|
|
$
|
26.12
|
|
$
|
24.55
|
____________
|
(1)
|
|
Oil includes natural gas liquids.
|
|
(2)
|
|
The Garland and Keystone fields were the only fields that contained 15% or more of the total proved reserve volumes of the underlying properties as of December 31, 2018. The Garland, Keystone and Rangely fields were the only fields that contained 15% or more of the total proved reserve volumes of the underlying properties as of December 31, 2017. The Garland and Rangely fields were the only field that contained 15% or more of the total proved reserve volumes of the underlying properties as of December 31, 2016.
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|
(3)
|
|
Production costs reported above exclude from lease operating expenses ad valorem taxes of $1.6 million ($1.38/BOE), $1.5 million ($1.28/BOE) and $1.4 million ($1.15/BOE) for the years ended December 31, 2018, 2017 and 2016, respectively.
|
Certain of the Trust’s wells are included in eight separate enhanced oil recovery waterflood projects, which include both secondary (waterflood) and tertiary (CO
2
injection) recovery efforts. Aggregate production from such enhanced oil recovery fields averaged 1,041 BOE/d during 2018 or 33% of 2018 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, 2018, approximately 55% of these properties were operated by Whiting. Based on annual 2018 production attributable to the underlying properties, approximately 82% of production was crude oil and natural gas liquids and 18% 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, 2018, the net production attributable to the underlying properties in the region was 519.8 MBOE or 1.4 MBOE/d.
Rocky Mountains Region.
The underlying properties in the Rocky Mountains region are located in Colorado, Wyoming, North Dakota and Montana. These properties consist of 14 fields of which Whiting operates wells in four. The Trust’s NPI does not include any of Whiting’s interests in the Bakken and Three Forks formations. The major fields in this region include the Rangely 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, 2018, the net production attributable to the underlying properties in the region was 476.5 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, 2018, the net production attributable to the underlying properties in the region was 117.1 MBOE or 0.3 MBOE/d.
Mid‑Continent Region.
The underlying properties in the Mid‑Continent region are located in Michigan, Arkansas, Oklahoma and Texas. These properties consist of seven fields of which Whiting operates wells in two. The major field in this region is the Whiting‑operated Wesson field located in Arkansas that produces from the Hogg Sand zone. For the year ended December 31, 2018, the net production attributable to the underlying properties in the region was 23.4 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, 2018, 2017 and 2016, there were seven, five and five gross wells, respectively, that were plugged and abandoned on the underlying properties, based on the determination that such wells were no longer economic to operate.
Divestitures.
Whiting may, without the consent of the Trust unitholders, require the Trust to sell the NPI associated with any well or lease that accounts for less than or equal to 0.25% of the total production from the underlying properties in the prior 12 months, provided that the NPI covered by such releases cannot exceed, during any 12‑month period, an aggregate fair market value to the Trust of $1.0 million. These releases will be made only in connection with a sale by Whiting of the relevant underlying properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such portion of the NPI. Any net sales proceeds paid to the Trust are distributable to Trust unitholders for the quarter in which they are received.
No sales of oil and gas wells occurred during the years ended December 31, 2018 and 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
.
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”).
These farm‑out agreements provide the third‑party partner with the option, but not the obligation, to drill one well in each of the leasehold sections or units, as the case may be, subject to the applicable farm‑out agreement, whereby the partner will pay 100% of the related drilling and well completion costs to earn a 75% working interest. As a result, the applicable underlying properties will consist of (i) 25% of the original working interest in these properties and (ii) an overriding royalty interest equal to the difference between 25% and the lease burdens of record. Upon completion of one well in each section or unit, as the case may be, pursuant to the terms of the applicable agreements, the partner has the option to drill (i) up to 15 additional wells under the Keystone South farm‑out, (ii) up to 12 additional wells under the Signal Peak farm‑out and (iii) one additional well under the Flying W farm‑out. For each of these additional optional wells, the partner is required to pay 85% of the drilling and well completion costs otherwise ascribed to the underlying properties for a 75% working interest. Given the Trust’s interest in the NPI, the Trust would be responsible for 13.5% of the underlying properties’ remaining drilling and well completion costs at the 90% NPI, subject to the average annual capital expenditure amount limitation as described in the “Computation of Net Proceeds” section in Item I of this Annual Report on Form 10‑K.
The third-party partner drilled and completed the first three wells pursuant to the terms of the Keystone South farm-out agreement during 2017, and a fourth well was drilled and completed during the second quarter of 2018, whereby the partner earned a 75% working interest in each of the underlying properties’ respective leasehold sections. The partner has no obligation to drill and complete any additional wells, and the Keystone South farm-out agreement will terminate during the second quarter of 2019 if no additional drilling has commenced by that time. In addition, the partner drilled and completed the first well under the Flying W farm-out during the second quarter of 2018, whereby the partner earned a 75% working interest in the underlying properties’ respective leasehold section. No drilling operations have occurred under the Signal Peak farm-out, and if no such drilling has commenced on or before September 30, 2019 the agreement will terminate.
Title to Properties
The underlying properties are subject to certain burdens that are described in more detail below. To the extent that these burdens and obligations affect Whiting’s rights to production and the value of production from the underlying properties, they have been taken into account in calculating the Trust’s interests and in estimating the size and value of the reserves attributable to the underlying properties.
Whiting’s interests in the oil and natural gas properties comprising the underlying properties are typically subject, in one degree or another, to one or more of the following:
|
·
|
|
royalties and other burdens on production, express and implied, under oil and natural gas leases;
|
|
·
|
|
overriding royalties, production payments and similar interests and other burdens on production created by Whiting or its predecessors in title;
|
|
·
|
|
a variety of contractual obligations arising under operating agreements, farm‑out agreements, production sales contracts and other agreements that may affect these properties or Whiting’s title thereto;
|
|
·
|
|
liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;
|
|
·
|
|
pooling, unitization and communitization agreements, declarations and orders;
|
|
·
|
|
easements, restrictions, rights‑of‑way and other matters that commonly affect property;
|
|
·
|
|
conventional rights of reassignment that obligate Whiting to reassign all or part of a property to a third party if Whiting intends to release or abandon such property; and
|
|
·
|
|
rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the underlying properties and the NPI therein.
|
Whiting has informed the Trustee that Whiting believes the burdens and obligations affecting the oil and natural gas properties comprising the underlying properties are conventional in the industry for similar properties. Whiting also has informed the Trustee that Whiting believes that the existing burdens and obligations do not, in the aggregate, materially interfere with the use of the underlying properties and do not materially adversely affect the value of the NPI.
At the time of its acquisitions of the underlying properties, Whiting undertook a title examination of these properties. As such, Whiting has informed the Trustee that Whiting believes its title to the underlying properties is, and the Trust’s title to the net profits interest is,
good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions as are not so material to detract substantially from the use or value of such properties or royalty interests.
Net profits interests are non‑operating, non‑possessory interests carved out of the oil and natural gas leasehold estate, but some jurisdictions have not directly determined whether a NPI is a real or a personal property interest. Whiting has recorded the conveyance of the NPI in the relevant real property records of all applicable jurisdictions. Whiting has informed the Trustee that Whiting believes the delivery and recording of the conveyance creates a fully conveyed and vested property interest under the applicable state’s laws, but because there is no direct authority to this effect in some jurisdictions, this may not always be the result. Whiting has also informed the Trustee that Whiting believes that it is possible the NPI may not be treated as a real property interest under the laws of certain of the jurisdictions where the underlying properties are located. Whiting has also informed the Trustee that Whiting believes that, if, during the term of the NPI, Whiting becomes involved as a debtor in a bankruptcy proceeding, the NPI relating to the underlying properties in most, if not all, of the jurisdictions should be treated as a fully conveyed property interest. In such a proceeding, however, a determination could be made that the conveyance constitutes an executory contract and the NPI is not a fully conveyed property interest under the laws of the applicable jurisdiction, and if such contract were not to be assumed in a bankruptcy proceeding involving Whiting, the Trust would be treated as an unsecured creditor of Whiting with respect to the NPI in the pending bankruptcy proceeding. Although no assurance can be given, Whiting has informed the Trustee that Whiting believes that the conveyance of the NPI relating to the underlying properties in most, if not all, of the jurisdictions of which these properties are located should not be subject to rejection in a bankruptcy proceeding as an executory contract.
Item 3.
Legal Proceedings
Currently, there are not any legal proceedings pending to which the Trust is a party or of which any of its property is the subject.
Item 4.
Mine Safety Disclosures
Not applicable.