Item 1.
Business
General
Whiting USA Trust I is a statutory trust formed in October 2007 under the Delaware Statutory Trust Act, pursuant to a trust agreement (the “Trust agreement”) among Whiting Oil and Gas as trustor, The Bank of New York Trust Company, N.A., as Trustee (subsequently renamed The Bank of New York Mellon Trust Company, N.A., and hereinafter referred to as “Trustee”), and Wilmington Trust Company, as Delaware Trustee (the “Delaware Trustee”). The initial capitalization of the Trust estate was funded by Whiting in November 2007. The Trust maintains its offices at the office of the Trustee, at 919 Congress Avenue, Austin, Texas 78701. The telephone number of the Trustee is 1-800-852-1422.
The Trust makes copies of its reports under the Exchange Act available at www.businesswire.com/cnn/whx.htm. The Trust’s filings under the Exchange Act are also available electronically from the website maintained by the Securities and Exchange Commission (“SEC”) at http://www.sec.gov. In addition, the Trust will provide electronic and paper copies of its recent filings free of charge upon request to the Trustee.
As of December 31, 2007, the Trust had no assets other than a de minimus cash balance from the initial capitalization and had conducted no operations other than organizational activities. In April 2008, the Trust issued 13,863,889 units of beneficial interest in the Trust (“Trust units”) to Whiting in exchange for the conveyance of a term net profits interest (“NPI”) by Whiting Oil and Gas. The NPI represents the right for the Trust to receive 90% of the net proceeds from Whiting’s interests in certain existing oil, natural gas and natural gas liquid producing properties which we refer to as “the underlying properties”. The underlying properties are located in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions. The underlying properties include interests in 3,077 gross (373.1 net) producing oil and gas wells. Immediately after the conveyance, Whiting completed an initial public offering of Trust units selling 11,677,500 such units. Whiting retained ownership of 2,186,389 Trust units, or 15.8% of the total Trust units issued and outstanding.
The NPI will terminate when 9.11 MMBOE have been produced and sold from the underlying properties (which amount is the equivalent of 8.20 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), and the Trust will soon thereafter wind up its affairs and terminate. As of December 31, 2010, on a cumulative accrual basis 3.90 MMBOE of the Trust’s total 8.20 MMBOE have been produced and sold and a cumulative 0.02 MMBOE have been divested. Further detail on the reserves is provided herein under the section titled “Properties-Description of the Underlying Properties - Reserves”, and such reserve information is based upon a reserve report prepared by independent reserve engineers Cawley, Gillespie & Associates, Inc. for the underlying properties at December 31, 2010, which we refer to as the “reserve report.” According to the reserve report, the portion of the 9.11 MMBOE (8.20 MMBOE at the 90% NPI) reserve quantities attributable to the NPI not yet produced or sold as divestitures at December 31, 2010 is projected to be produced from the underlying properties by November 30, 2015, and the reserve report is based on the assumptions included therein. See “Risk Factors” in Item 1A
Item 1A.
Risk Factors
The amounts of cash distributions by the Trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquid 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 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. These factors include, among others:
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changes in global supply and demand for oil and gas;
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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 gas;
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political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity;
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the level of global oil and gas exploration and production activity;
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the level of global oil and gas inventories;
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weather conditions;
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technological advances affecting energy consumption;
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domestic and foreign governmental regulations;
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proximity and capacity of oil and gas pipelines and other transportation facilities;
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the price and availability of competitors’ supplies of oil and gas in captive market areas; and
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the price and availability of alternative fuels.
Lower prices of oil, natural gas and natural gas liquids will reduce the amount of the 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 of oil, natural gas or natural gas liquids will reduce the amount of cash available for distribution to the Trust unitholders.
Moreover, government regulations, such as regulation of natural gas gathering and transportation and possible price controls, can affect commodity prices in the long term.
Financial returns to purchasers of Trust units will vary in part based on how quickly 9.11 MMBOE are produced and sold from the underlying properties, and it is not known when that will occur.
The NPI will terminate at the time when 9.11 MMBOE have been produced and sold from the underlying properties (which amount is the equivalent of 8.20 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI). The reserve report prepared by the Trust’s independent petroleum engineer dated as of December 31, 2010 (the “reserve report”) projects that 9.11 MMBOE will have been produced and sold from the underlying properties by November 30, 2015. However, the exact rate of production cannot be predicted with certainty and such amount may be produced before or after the date projected by the reserve report. If production attributable to the underlying properties is slower than estimated, then financial returns to Trust unitholders will be lower assuming constant prices because cash distributions attributable to such production will occur at a later date.
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 net profits interests 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 and proceeds, if any, received by Whiting upon settlement of the hedge contracts. The reserves attributable to the underlying properties are depleting assets, which means that those reserves will decline over time. For example, the current year reserve report reflects an aggregate depletion percentage of 93.8%, which is the percentage of the estimated ultimate total production from the underlying properties on a full economic life basis that has been produced from the properties’ inception through December 31, 2010. Total oil and natural gas production attributable to the underlying properties declined 9.2% from 2008 to 2009 and 7.7% from 2009 to 2010. Also based on the 2010 reserve report, production attributable to the underlying properties is expected to decline at rates ranging from 9% to 11% annually from 2011 and 2015. 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. Also, the anticipated rate of decline is an estimate and actual decline rates will likely vary from those estimated.
The NPI will terminate at the time when 9.11 MMBOE (8.20 MMBOE at the 90% NPI) have been produced and sold from the underlying properties, which is projected by the reserve report to occur by November 20, 2015. As of December 31, 2010, on a cumulative accrual basis 3.90 MMBOE of the Trust’s total 8.20 MMBOE have been produced and sold and a cumulative 0.02 MMBOE have been divested. Furthermore, 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 NPI to replace the depleting assets and production attributable to the NPI.
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. In addition, Whiting is not required to make any capital expenditures.
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.
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 to the Trust unitholders will depend 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 both positively and negatively 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 expenses, gathering and transportation costs, severance and excise taxes and capital expenditures.
Changes in these assumptions can materially increase or decrease production and reserve estimates. The estimated reserves attributable to the NPI and the estimated future net revenues 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.
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 will depend upon, among other things, oil, natural gas and natural gas liquid production and prices 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 will reduce 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. In addition, curtailments or damage to pipelines used to transport oil, natural gas and natural gas liquid 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 liquid 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.
The Trust and the Trust unitholders have no voting or managerial rights with respect to the underlying properties. As a result, neither the Trust nor the unitholders have any ability to influence the operation of the underlying properties.
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. Also, the Trust unitholders have no voting rights with respect to the operators of these properties and, therefore, have no managerial, contractual or other ability to influence the activities of the operators of these properties.
Whiting has limited control over activities on certain of the underlying properties Whiting does not operate, which could reduce production from the underlying properties and cash available for distribution to Trust unitholders.
Whiting is currently designated as the operator of approximately 64% of the underlying properties based on the December 31, 2010 standardized measure of discounted future net cash flows. However, for the 36% of the underlying properties that Whiting does not operate, Whiting does not have control over normal operating procedures or expenditures 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 timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells, and use of technology. 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.
Whiting is not required to make capital expenditures on the underlying properties at historical levels or at all. If Whiting does not make capital expenditures, then the timing of production from the underlying properties may not be accelerated.
Whiting has made capital expenditures on the underlying properties, which has increased production from the underlying properties. However, Whiting has no contractual obligation to make capital expenditures on the underlying properties in the future. Furthermore, for properties on which Whiting is not designated as the operator,
the decision whether to make capital expenditures is made by the operator and Whiting has no control over the timing or amount of those capital expenditures. Whiting also has the right to non-consent and not participate in the capital expenditures on these properties, in which case Whiting and the Trust will not receive the production resulting from such capital expenditures. Accordingly, it is likely that capital expenditures with respect to the underlying properties will vary from and may be less than historical levels.
Whiting may abandon individual wells or properties that it reasonably believes to be uneconomic.
Whiting may abandon any well if it reasonably believes 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.
The amount of cash available for distribution by the Trust is reduced by the amount of any royalties, lease operating expenses, production and property taxes, maintenance expenses, post-production costs and producing overhead, and payments made with respect to the hedge contracts.
Production costs on the underlying properties are deducted in the calculation of the Trust’s share of net proceeds. In addition, production and property taxes and any costs or payments associated with post-production costs are deducted in the calculation of the Trust’s share of net proceeds. Accordingly, higher or lower production expenses, taxes and post-production costs directly decrease or increase the amount received by the Trust in respect of its NPI. The amount of net proceeds subject to the NPI is also reduced by all payments made by Whiting to the hedge contract counterparty upon settlement of the hedge contracts.
If production costs of the underlying properties and payments made by Whiting to the hedge contract counterparty exceed the proceeds of production, 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.
If the payments received by Whiting under the hedge contracts and certain other non-production revenue exceed operating expenses during a quarterly period, then the ability to use such excess amounts to offset operating expenses will be deferred until the next quarterly period when such amounts are less than such expenses.
If the hedge payments received by Whiting and certain other non-production revenue exceed the operating expenses during a quarterly period, the ability to use such excess amounts to offset operating expenses will be deferred until the next quarterly period when such amounts are less than such expenses. If such amounts are deferred, then the applicable quarterly distribution will be less than it would have otherwise been. However, if any excess amounts have not been used to offset costs at the time when 9.11 MMBOE have been produced and sold from the underlying properties, which is the time when the NPI will terminate, then unitholders will not be entitled to receive the benefit of such excess amounts. Such a scenario could occur if oil and natural gas prices decline significantly through December 31, 2012 and remained low for the remainder of the term.
An increase in the differential between the NYMEX or other benchmark price of oil and natural gas and the wellhead price received could reduce cash distributions by the Trust and the value of Trust units.
The prices received for oil and natural gas production from the underlying properties is usually sold at a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the price received is called a differential. The differential may vary significantly due to market conditions, the quality and location of production and other factors. Whiting cannot accurately predict oil and natural gas differentials. Increases in the differential 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.
Shortages or increases in costs of oil field equipment, services and qualified personnel could reduce 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 and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. 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, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could significantly decrease the amount of cash available for distribution to the Trust unitholders, or restrict operations on the underlying properties.
The hedge contracts will limit the potential for increases in cash distributions due to oil and natural gas price increases through December 31, 2012 and will not provide any price support after December 31, 2012.
Whiting has entered into hedge contracts, which are structured as costless collar arrangements that will hedge approximately 71% and 65%, respectively, of the oil and natural gas volumes expected to be produced from the underlying properties through December 31, 2012. These hedge contracts, however, do not cover all of the oil and natural gas volumes that are expected to be produced during the term of the Trust. Because of the differential between NYMEX or other benchmark prices of oil and natural gas and the wellhead price received, hedge contracts may not totally offset the effects of price fluctuations. Whiting has not entered into any hedge contracts relating to oil and natural gas volumes expected to be produced after 2012, and the terms of the conveyance of the NPI prohibit Whiting from entering into new hedging arrangements. As a result, the amounts of the cash distributions may fluctuate significantly after 2012 as a result of changes in commodity prices because there will be no hedge contracts in place to reduce the effects of any changes in commodity prices. The hedge contracts may also limit the amount of cash available for distribution if prices increase. In addition, the hedge contracts are subject to the nonperformance of the counterparty and other risks. For a discussion of the hedge contracts, see “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of this Annual Report on Form 10-K.
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 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 Trustee must also sell the NPI if the annual gross proceeds attributable to the NPI are less than $1.0 million for each of any two consecutive years. The sale of the NPI will result in the dissolution of the Trust. The net proceeds of any such sale will be distributed to the Trust unitholders.
The NPI will terminate at the time when 9.11 MMBOE (8.20 MMBOE at the 90% NPI) have been produced and sold from the underlying properties. 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 likely diminish towards the end of the term of the NPI because the cash distributions from the Trust will cease at the termination of such NPI and the Trust will have no right to any additional production from the underlying properties after the term of the NPI.
The disposal by Whiting of its remaining Trust units may reduce the market price of the Trust units.
Whiting owns 15.8% of the Trust units. If Whiting sells these units, then the market price of the Trust units may be reduced. Whiting and the Trust have entered into a registration rights agreement pursuant to which the Trust has agreed to file a registration statement or shelf registration statement to register the resale of the remaining Trust units held by Whiting and any transferee of the Trust units upon request by such holders.
The market price for the Trust units may not reflect the value of the NPI held by the Trust.
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 prices for sales of oil, natural gas and natural gas liquid production attributable to the underlying properties. 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 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.
Conflicts of interest could arise between Whiting and the Trust unitholders.
The interests of Whiting and the interests of the Trust and the Trust unitholders with respect to the underlying properties could at times differ. For example, Whiting has the right, subject to significant limitations, 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 such 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. Additionally, 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. Whiting has broad discretion over the timing and amount of operating expenditures and activities, including workover expenses and activities, which could result in higher costs being attributed to the NPI. 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 managed 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 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. Whiting owns approximately 15.8% of the outstanding Trust units. As a result, it may be difficult to remove or replace the Trustee without the approval of Whiting.
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 likely 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 will not be able to sue Whiting to enforce these rights.
Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.
Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations under the General Corporation Law of the State of Delaware. Courts in jurisdictions outside of Delaware, however, may not give effect to such limitation.
The operations of the underlying properties may result in significant costs and liabilities with respect to environmental and operational safety matters, which could reduce the amount of cash available for distribution to Trust unitholders.
Significant costs and liabilities can be incurred as a result of environmental and safety requirements applicable to the oil and natural gas exploration, development and production activities of the underlying properties. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws, regulations, and enforcement policies, which legal requirements have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts on the operations of the underlying properties.
Strict, joint and several liability may be imposed under certain environmental laws and regulations, which could result in liability for the conduct of others or for the consequences of one’s own actions that were in compliance with all applicable laws at the time those actions were taken. 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 operations of the underlying properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the 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 gasses” 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.
On December 15, 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 warming of the Earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted regulations that could trigger permit review for GHG emissions from certain stationary sources. The EPA has also issued regulations that require the establishment and reporting of an inventory of GHG emissions from specified stationary sources, including certain onshore oil and natural gas exploration, development and production facilities. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHG gases from, equipment and operations could require Whiting to incur costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the natural gas it produces.
More than one-third of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although most of the state-level initiatives have to date focused on large sources of GHG emissions, such
as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. Finally, it should be noted that some 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, and 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 Trust unitholders.
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 a debt instrument for federal income tax purposes, the Trust unitholders may receive different and less advantageous tax treatment than they anticipated.
If the NPI were not treated as a debt instrument, the 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 Trust has requested a ruling from the IRS regarding these tax questions, and neither Whiting nor the Trust can assure you that such a ruling would be granted if requested or that the IRS will not challenge this position on audit. 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’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 an 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 such NPI in the pending bankruptcy proceeding.
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 64% of the underlying properties based on the December 31, 2010 standardized measure of discounted future net cash flows. 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. In addition,
Whiting is obligated to use the proceeds it receives upon the settlement of the hedge contracts to offset operating expenses relating to the underlying properties, with certain restrictions.
Whiting has entered into hedge contracts, consisting of costless collar arrangements, with JPMorgan Chase Bank National Association to reduce the exposure of the revenue from oil and natural gas production from the underlying properties to fluctuations in crude oil and natural gas prices in order to achieve more predictable cash flow. Crude oil collar arrangements settle based on the average of the settlement price for each commodity business day in the contract period, while natural gas collar arrangements settle based on an end of month price. In the collar arrangements, the counterparty is required to make a payment to Whiting for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. Whiting is required to make a payment to the counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price.
Whiting’s ability to perform its obligations related to the operation of the underlying properties, its obligations to the counterparty related to the hedge contracts 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. For example, Whiting’s net loss for 2009 was $117.2 million, and although it increased to net income of $272.7 million for 2010, 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 Trust’s receipt of payments based on the hedge contracts depends upon the financial position of the hedge contract counterparty and Whiting. A default by the hedge contract counterparty or Whiting could reduce the amount of cash available for distribution to the Trust unitholders.
In the event that the counterparty to the hedge contracts defaults on its obligations to make payments to Whiting under the hedge contracts, the cash distributions to the Trust unitholders could be materially reduced as the hedge payments are intended to provide additional cash to the Trust during periods of lower crude oil and natural gas prices. In addition, because the hedge contracts are with a single counterparty, JPMorgan Chase Bank National Association, the risk of default is concentrated with one financial institution. Whiting cannot provide any assurance that this counterparty will not become a credit risk in the future. The hedge contracts also have default terms applicable to Whiting, including customary cross default provisions. If Whiting were to default, the counterparty to the hedge contracts could terminate the hedge contracts and the cash distributions to Trust unitholders could be materially reduced during periods of lower crude oil and natural gas prices.
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 9.11 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 any consideration for such reconveyance of a portion of the NPI. Such reconveyance of a portion of the NPI may extend the time it takes for 9.11 MMBOE (8.20 MMBOE at the 90% NPI) to be produced from the underlying properties for purposes of the NPI.
Item 1B.
Item 1B.
Unresolved Staff Comments.
None.
Item 2.
Item 2.
Properties.
Description of the Underlying Properties
The underlying properties consist of Whiting’s net interests in certain oil and natural gas producing properties as of the date of the conveyance of the NPI to the Trust, which are located primarily in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions of the United States. The underlying properties include interests in 3,077 gross (373.1 net) producing oil and natural gas wells located in 169 fields on approximately 204,900 gross (75,000 net) acres in 14 states. Whiting has acquired interests in these properties through various acquisitions that have occurred during its 28 year existence prior to the conveyance. For the year ended December 31, 2010, the net production attributable to the underlying properties was 1,332 MBOE or 3.7 MBOE/d. Whiting operates approximately 64% of the underlying properties based on the December 31, 2010 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 of development and operation of 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, consisting primarily of royalty interests retained by the owners of the land subject to the working interests. These landowners’ 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 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 9.11 MMBOE (8.20 MMBOE at the 90% NPI) of production from the underlying properties. As of December 31, 2010, on a cumulative accrual basis 3.90 MMBOE of the Trust’s total 8.20 MMBOE have been produced and sold, a cumulative 0.02 MMBOE have
been divested, and the remaining balance is expected to be produced by November 30, 2015, based on the Trust’s year-end 2010 reserve report. However, the reserve report is based on the assumptions included therein. See “Risk Factors” in Item 1A of this Annual Report on Form 10-K for additional discussion. The rate of future production cannot be predicted with certainty, and 9.11 MMBOE (8.20 MMBOE at the 90% NPI) 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 full life of the properties, whereas the Trust is entitled to only receive 90% of the net proceeds from the sale of production of oil, natural gas and natural gas liquids attributable to the underlying properties during the term of the NPI.
Whiting’s 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. The Trust units retained by Whiting represent 15.8% of the Trust units outstanding. Whiting’s retained ownership interests in the underlying properties and its ownership of Trust units considered together entitle Whiting to receive approximately 24.2% of the net proceeds from the underlying properties during the term of the Trust, thereby providing Whiting 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 these properties as a reasonably prudent operator in the same manner that it would operate them if these properties were not burdened by the NPI, and Whiting has agreed to use commercially reasonable efforts to cause the other operators to operate these properties in the same manner.
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 rates ranging from 9% to 11% annually from 2011 through 2015. 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.
Reserves
As of December 31, 2010, all of our oil and gas reserves are attributable to properties within the United States. The following table summarizes estimated proved reserves (developed and undeveloped) and the standardized measure of discounted future net cash flows as of December 31, 2010 based on average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the
12-month period ended December 31, 2010) attributable to the Trust and underlying properties’ full economic life (dollars in thousands):
Summary of Oil and Gas Reserves as of Fiscal-Year End Based on Average Fiscal-Year Prices
(1)
Standardized measure as of December 31, 2010. 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.
(2)
The underlying properties’ estimated proved reserves as of December 31, 2010 on a 90% basis were 4,323 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.
(3)
Oil includes natural gas liquids.
The above tables do not include any proved undeveloped reserve quantities as of December 31, 2010 because the underlying properties consist of mature producing properties that are essentially fully developed. Technical studies have not identified any drilling locations that meet the criteria of proved undeveloped reserves, nor has any future capital been committed for the development of proved undeveloped reserves on the underlying properties.
Proved reserves. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. Oil and gas reserve quantities and related discounted future net cash flows have been derived from oil and gas prices calculated using an average of the first-day-of-the month price for each month within the most recent 12 months, pursuant to current SEC and FASB guidelines. Assumptions used to estimate reserve quantities and related discounted future net cash flows also include costs for estimated future production expenditures required to produce the proved reserves as of December 31, 2010. Future net cash flows are discounted at an annual rate of 10%. There is no provision for federal income taxes with respect to the future net cash flows attributable to the underlying properties or to the NPI because future net revenues are not subject to taxation at the Trust level. See “Federal Income Tax Matters” in Item 1 of this Annual Report on Form 10-K for more information.
A rollforward of changes in net proved reserves attributable to the Trust from January 1, 2008 to December 31, 2010 and the calculation of the standardized measure of the related discounted future net revenues are contained in the Supplemental Oil And Gas Reserve Information (Unaudited) in the notes to the financial statements of the Trust included in this Annual Report on Form 10-K. Whiting has not filed reserve estimates covering the underlying properties with any other federal authority or agency.
In 2010, revisions to previous estimates increased proved reserves by a net amount of 32 MBOE. Included in these revisions were 1.4 Bcf of upward adjustments to natural gas primarily due to higher gas prices of $4.17 per Mcf in reserve estimates at December 31, 2010, as compared to gas prices of $3.15 per Mcf at December 31, 2009. This upward revision in natural gas was almost entirely offset, however, by 201 MBbl of downward adjustments to crude oil reserves. Crude oil reserves declined in 2010 primarily due to adjustments to production accruals, which decreases were partially offset by higher oil prices of $68.77 per Bbl in reserve estimates at December 31, 2010, as compared to $51.58 per Bbl of oil at December 31, 2009.
Preparation of reserves estimates. Whiting has advised the Trust 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 external quarterly reviews, annual audits and 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 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 and Midland offices to review field performance. Following these reviews 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 primary contact at CG&A is Mr. Robert Ravnaas, Executive Vice President. Mr. Ravnaas is a State of Texas Licensed Professional Engineer. See Appendix 1 and Exhibit 99 of this Annual Report on Form 10-K for the Report of Cawley, Gillespie & Associates, Inc. and further information regarding the professional qualifications of Mr. Ravnaas.
Whiting’s Vice President of Reservoir Engineering and Acquisitions is responsible for overseeing the preparation of the reserves estimates. He has over 37 years of experience, the majority of which has involved reservoir engineering and reserve estimation, holds a Bachelor’s Degree in Petroleum Engineering from the University of Wyoming, holds an MBA from the University of Denver and is a registered Professional Engineer. He has also served on the national Board of Directors of the Society of Petroleum Evaluation Engineers.
As noted above, the current reserve report projects that 9.11 MMBOE attributable to the NPI will be produced from the underlying properties by November 30, 2015, which differs from the October 31, 2017 projected date in the December 31, 2009 reserve report. This change is primarily due to the higher price assumptions being used in the independent engineers’ report as of December 31, 2010 as compared to the reserve report prepared as of
December 31, 2009. The application of the higher prices in the reserve estimates extends the estimated economic producing lives and increases the estimated overall recoverable reserve quantities of wells producing at lower rates. The projected time to produce the remaining reserves attributable to the Trust is therefore reduced. Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the estimates. In addition, the reserves and net revenues attributable to the NPI include only 90% of the reserves attributable to the underlying properties that are expected to be produced within the term of the NPI.
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 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 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, 2010. Undeveloped acreage is not significant.
The following is a summary of the producing wells on the underlying properties as of December 31, 2010:
The following is a summary of the number of developmental wells drilled on the underlying properties during the last three years. A dry well is an exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. A productive well is an exploratory, development or extension well that is not a dry well. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves found. Whiting did not drill any exploratory wells on
the underlying properties during the periods presented. There were three wells being drilled as of December 31, 2010.
Oil and Natural Gas Production
The table below shows total oil and gas production, average sales prices and average production costs attributable to underlying properties. The underlying properties’ information is presented in the table below on a cash basis, as this basis of accounting is consistent with the Trust’s financial statements which have been prepared on a modified cash basis.
(1)
No field contained 15% or more of the total proved reserve volumes at December 31, 2010, 2009 or 2008.
(2)
Production costs reported above exclude from lease operating expenses ad valorem taxes of $1.0 million ($0.78/BOE), $0.9 million ($0.65/BOE) and $1.3 million ($0.82/BOE) for the years ended December 31, 2010, 2009 and 2008, respectively.
Producing wells the Trust has an interest in are part of 14 enhanced oil recovery waterflood projects, and aggregate production from such enhanced oil recovery fields averaged 657 BOE/d during 2010 or 18% of our 2010 daily production. For these areas, we need to use enhanced recovery techniques in order to maintain oil and gas production from these fields.
Delivery Commitments
Neither the Trust nor the underlying properties are committed to deliver fixed quantities of oil or 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. Whiting believes this broad distribution provides a buffer against regional trends that may negatively impact production or prices. Based on the standardized measure of discounted future net cash flows at December 31, 2010, approximately 64% of these properties were operated by Whiting. Based on annual 2010 production attributable to the underlying properties, approximately 60% was oil and natural gas liquids and 40% was natural gas. These properties are located in mature fields and have established production profiles. However, production and distributions to the Trust will decline over time.
Mid-Continent Region. The underlying properties in the Mid-Continent region are located in Arkansas, Oklahoma, Kansas and Michigan. These properties include 57 fields of which Whiting operates wells in 28 of these fields. There are two significant fields located in Arkansas. The Magnolia Smackover Pool Unit, the largest single field in the underlying properties, produces from the Smackover Lime. The second Arkansas field is the Stephens-Smart field, producing from the Buckrange and Travis Peak. The major fields and areas in Oklahoma are located in the Anadarko Basin and include Putnam Field, Mocane-Laverne Gas Area, Sho-Vel-Tum Field and Nobscot Northwest Field, which primarily produce from the Oswego, Hunton, Penn, Morrow, Red Fork and Cottage Grove zones. Case Field is the major Michigan field in the region and produces from the Silurian Niagaran zone. For the year ended December 31, 2010, the net production attributable to the underlying properties in the region was 515.9 MBOE or 1.4 MBOE/d.
Rocky Mountains Region. The underlying properties in the Rocky Mountains region are located in two distinct areas. The first, from which crude oil is primarily produced, includes the Williston Basin in North Dakota and Montana as well as the Bighorn and Powder River Basins of Wyoming, while the second, from which natural gas is primarily produced, includes southwest Wyoming, Colorado and Utah. These properties include 61 fields of which Whiting operates wells in 31 of these fields. The major North Dakota fields in this region include Bell Field and Fryberg Field that produce from Tyler sandstone; Whiskey Joe, Teddy Roosevelt, Sherwood and Davis Creek Fields that produce from various intervals in the Madison; Hiline Unit that produces from the Lodgepole; and Big Dipper Field that produces from the Duperow and Red River zones. In Montana, the major fields include the Bainville Field and Palomino Fields that produce primarily from the Nisku zone, and Oxbow Field that produces from the Nisku and Red River zones. The major Wyoming fields in this region include the Sage Creek Field in the Bighorn Basin that produces from the Tensleep and Madison zones and the Kiehl Field in the Powder River Basin, which produces from the Minnelusa formation and is under waterflood. The Ignacio Blanco Field is the major Colorado field in this region and produces from the Fruitland Coal zone. For the year ended December 31, 2010, the net production attributable to the underlying properties in the region was 468.3 MBOE or 1.3 MBOE/d.
Permian Basin Region. The Permian Basin Region of West Texas and New Mexico 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 include 28 fields of which Whiting operates wells in
10 of these fields. The major fields in this region include Iatan East Howard Field, which produces from the San Andres, Glorieta and Clearfork zones; the Fullerton Field, which is unitized and produces from the Clearfork zone; and Patricia Field, which produces from the Sprayberry and Fusselman zones. For the year ended December 31, 2010, the net production attributable to the underlying properties in the region was 193.7 MBOE or 0.5 MBOE/d.
Gulf Coast Region. The underlying properties in the Gulf Coast region are located in Texas, Louisiana, Mississippi and Alabama. These properties include 23 onshore fields of which Whiting operates wells in one of these fields. The major field in this region is the Mestena Grande Field located in Texas, which produces from the Queen City zone. For the year ended December 31, 2010, the net production attributable to the underlying properties in the region was 154.4 MBOE or 0.5 MBOE/d.
Abandonment and Sale of Underlying Properties
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 or eliminate 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 if these properties were not burdened by the NPI, and Whiting has agreed to use commercially reasonable efforts to cause the other operators to operate these properties in the same manner. For the years ended December 31, 2010, 2009 and 2008, twenty, seventeen and seven gross wells, respectively, were plugged and abandoned on the underlying properties, based on the determination that such wells were no longer economic to operate.
In addition, Whiting may, without the consent of the Trust unitholders, require the Trust to release the NPI associated with any lease that accounts for less than or equal to 0.25% of the total production from the underlying properties in the prior 12 months and provided that the NPI covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the Trust of $500,000. 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 NPI. Any net sales proceeds paid to the Trust are distributable to Trust unitholders for the quarter in which they are received. During 2010, Whiting received aggregate sale proceeds of $3,172 in exchange for its divestiture of Trust properties that held 0.7 MBOE of proved reserves. Whiting includes all such proceeds from Trust property divestitures in its NPI distributions to the Trust.
Title to Properties
The underlying properties are subject to certain burdens that are described in more detail below. To the extent that these burdens and obligations affect Whiting’s rights to production and the value of production from the underlying properties, they have been taken into account in calculating the Trust’s interests and in estimating the size and the value of the reserves attributable to the underlying properties.
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, overriding royalties and other burdens, express and implied, under oil and natural gas leases;
•
overriding royalties, production payments and similar interests and other burdens 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 the underlying properties or their title;
•
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 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.
Whiting acquired the underlying properties in various transactions that have occurred during its 28 year existence prior to the conveyance. At the time of its acquisitions of the underlying properties, Whiting undertook a title examination of these properties.
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 Trust, 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 that 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 such NPI in the pending bankruptcy proceeding. Although no assurance can be given, Whiting has informed the Trustee that Whiting believes that the
conveyance of the NPI relating to the underlying properties in most, if not all, of the jurisdictions of which these properties are located should not be subject to rejection in a bankruptcy proceeding as an executory contract.
Item 3.
Item 3.
Legal Proceedings.
Currently, there are not any legal proceedings pending to which the Trust is a party or of which any of its property is the subject.
Item 4.
Item 4.
Removed and Reserved.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
The Trust units commenced trading on the New York Stock Exchange on April 30, 2008 under the symbol “WHX.” Prior to April 30, 2008, there was no established public trading market for the Trust units. The high and low sales prices per unit for each quarter in 2010 and 2009 were as follows:
At December 31, 2010, the 13,863,889 units outstanding were held by three unitholders of record.
Distributions
Each quarter, the Trustee determines the amount of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the NPI and other sources (such as interest earned on any amounts reserved by the Trustee) that quarter, over the Trust’s expenses for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities. Quarterly cash distributions during the term of the Trust are made by the Trustee generally no later than 60 days following the end of each quarter (or the next succeeding business day) to the Trust unitholders of record on the 50th day following the end of each quarter (or the next succeeding business day). The table below presents the net cash proceeds for each quarter of 2010 and 2009 attributable to the 90% NPI, the estimated Trust expenses, Montana state income taxes reserved for by the Trustee and the resulting distributable income per Trust unit (dollars in thousands, except distributable income per unit).
Subsequent to year end, on March 1, 2011, a distribution of $0.667847 per Trust unit was paid to Trust unitholders owning Trust units as of February 21, 2011. The distribution consisted of net cash proceeds of $9.3 million paid by Whiting to the Trust, which included cash receipts of $1.4 million (90% of $1.6 million) for commodity derivative contracts settled for October 1, 2010 through December 31, 2010, less a provision of $250,000 for estimated Trust expenses and $57,719 for Montana state income tax withholdings.
Equity Compensation Plans
The Trust does not have any employees and, therefore, does not maintain any equity compensation plans.
Recent Sales of Unregistered Securities
None.
Purchases of Equity Securities
There were no purchases of Trust units by the Trust or any affiliated purchaser during the fourth quarter of 2010.
Item 6.
Item 6.
Selected Financial Data.
The Trust was formed on October 18, 2007. The conveyance of the NPI, however, did not occur until April 30, 2008. As a result, the Trust did not recognize any income or make any distributions during the first quarter of 2008. The following table sets forth selected data for the Trust for the years ended December 31, 2010, 2009 and 2008 and as of December 31, 2010, 2009 and 2008 based on the Trust’s audited financial statements (dollars and shares in thousands, except distributable income per unit).
Item 7.
Item 7.
Trustee’s Discussion and Analysis of Financial Condition and Results of Operation.
This document contains forward-looking statements, which give our current expectations or forecasts of future events. Please refer to “Forward-Looking Statements” which follows the Table of Contents of this Form 10-K for an explanation of these types of statements.
Overview
The Trust does not conduct any operations or activities. The Trust’s purpose is, in general, to hold the NPI, to distribute to the Trust unitholders cash that the Trust receives in respect of the NPI, and to perform certain administrative functions in respect of the NPI and the Trust units. The Trust derives substantially all of its income and cash flows from the NPI, which is in turn subject to commodity hedge contracts.
Although oil prices fell significantly after reaching a high in the third quarter of 2008, they have experienced a rebound in the second half of 2009 and first nine months of 2010 (as only the first nine months of oil prices affect 2010 NPI distributions). Additionally, natural gas prices have fallen significantly since their peak in the third quarter of 2008 and have remained low throughout 2009, but gas prices have begun to slightly increase during the first nine months of 2010 (as only the first eight months of gas prices affect 2010 NPI distributions). The following table highlights these price trends by listing quarterly average NYMEX crude oil and natural gas prices for the periods indicated:
Lower oil and gas prices on production from the underlying properties could cause the following: (i) a reduction in the amount of net proceeds to which the Trust is entitled; (ii) a reduction in the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties; and (iii) an extension of the length of time required to produce 9.11 MMBOE (8.20 MMBOE at the 90% NPI) due to some wells thereby reaching their economic limits sooner.
For a discussion of the estimated date when 9.11 MMBOE (8.20 MMBOE at the 90% NPI) will be produced and sold from the underlying properties and when the Trust will soon thereafter wind up its affairs and terminate, see “Description of the Underlying Properties” in Item 2 of this Annual Report on Form 10-K. For a discussion of material changes to proved reserves, see “Reserves” in Item 2 of this Annual Report on Form 10-K. Additionally, for a discussion of the need to use enhanced recovery techniques, see “Oil and Natural Gas Production” in Item 2 of this Annual Report on Form 10-K.
Results of Trust Operations
The Trust was formed in October 2007. The conveyance of the NPI, however, did not occur until April 2008. As a result, the Trust did not recognize any income or make any distributions during the first quarter of 2008. The following is a summary of income from net profits interest received by the Trust for the years ended December 31, 2010 and 2009, consisting of the February, May, August and November distributions for each respective year, as well as income from net profits interest for the year ended December 31, 2008, consisting of the May, August and November NPI distributions for that year (dollars in thousands, except per Bbl, per Mcf and per BOE amounts):
Trust Results
(a)
Oil and gas sales volumes and related revenues for the year ended December 31, 2010 (consisting of Whiting’s February, May, August and November 2010 NPI distributions to the Trust) generally represent crude oil production from October 2009 through September 2010 and natural gas production from September 2009 through August 2010.
(b)
Oil and gas sales volumes and related revenues for the year ended December 31, 2009 (consisting of Whiting’s February, May, August and November 2009 NPI distributions to the Trust) generally represent crude oil production from October 2008 through September 2009 and natural gas production from September 2008 through August 2009.
(c)
Oil and gas sales volumes and related revenues for the year ended December 31, 2008 (consisting of Whiting’s May, August and November 2008 NPI distributions to the Trust) generally represent crude oil production from January through September 2008 and natural gas production from January through August 2008.
Comparison of Results of the Trust for the Years Ended December 31, 2010 and 2009
Income from Net Profits Interest. Income from net profits interest is recorded on a cash basis when NPI proceeds are received by the Trust from Whiting. NPI proceeds that Whiting remits to the Trust are based on the oil and gas production Whiting has received payment for within one month following the end of the most recent fiscal quarter. Whiting receives payment for its crude oil sales generally within 30 days following the month in which it is produced, and Whiting receives payment for its natural gas sales generally within 60 days following the month in which it is produced. Income from net profits interest is generally a function of oil and gas revenues, lease operating expenses, production taxes and cash settlements on commodity derivatives as follows:
Revenues. Oil and natural gas revenues increased $10.7 million or 19% in 2010 compared to 2009. Revenues are a function of average sales prices and volumes sold. In 2010, oil and gas revenues and NPI distributions were positively impacted by a substantial increase in realized commodity prices. The average price realized for oil before the effects of hedging increased 35% between periods, and the average price realized for natural gas before the
effects of hedging increased 3%. Partially offsetting the significant increase in commodity prices was a decrease in production volumes sold between periods. Oil sales volumes decreased 5% or 43 MBOE, and gas sales volumes decreased 9% or 329 MMcf for the year ended December 31, 2010 as compared to 2009, primarily due to normal field production decline. Oil and gas production attributable to the underlying properties is estimated to decline at rates ranging from 9% to 11% annually from 2011 to 2015, based on the reserve report prepared by the Trust’s independent reservoir engineers as of December 31, 2010.
Lease Operating Expenses. Lease operating expenses decreased $2.5 million or 10% from 2009 to 2010 due to a lower amount of operating costs charged to wells that are not operated by Whiting, a decline in labor costs on Whiting-operated properties and a decrease in gathering fees between periods. Lease operating expenses per BOE decreased from $17.96 in 2009 to $17.39 for 2010. The 3% decrease on a BOE basis was primarily caused by a lower amount of operating costs charged to wells that are not operated by Whiting.
Production Taxes. Production taxes are generally calculated as a percentage of oil and gas revenues before the effects of hedging. Tax credits and exemptions allowed in the various taxing jurisdictions are generally utilized to their potential. Production taxes during 2010 increased $0.8 million or 20% compared to 2009, primarily due to higher oil and natural gas sales between periods. Production taxes as a percent of oil and gas revenues for 2010 and 2009 were 7.1% and 7.0%, respectively.
Cash Settlements on Commodity Derivatives. Whiting entered into certain costless collar hedge contracts for the benefit of the Trust prior to the conveyance. If current market prices are lower than a collar’s price floor when the cash settlement amount is calculated, Whiting receives cash proceeds from the contract counterparty. Conversely, if current market prices are higher than a collar’s price ceiling when the cash settlement amount is calculated, Whiting is required to pay the contract counterparty. Cash settlements relating to the hedges resulted in a gain of $4.3 million for the year ended December 31, 2010, which had the effect of increasing average sales prices net of hedging by $0.25 per Bbl of oil and $1.23 per Mcf of natural gas. For the same period in 2009, cash settlements relating to these hedges resulted in a gain of $16.7 million, or $14.21 per Bbl of oil and $1.26 per Mcf of natural gas.
Distributable Income. For the year ended December 31, 2010, the Trust’s distributable income was $37.4 million and was based on income from net profits interest of $38.4 million less general and administrative expenses of $0.9 million and Montana state income tax withholdings of $0.2 million. This compares to distributable income of $37.1 million during 2009, which was based on income from net profits interest of $38.3 million less general and administrative expenses of $0.9 million and $0.2 million in Montana state income tax withholdings.
Comparison of Results of the Trust for the Years Ended December 31, 2009 and 2008
Income from Net Profits Interest. Income from net profits interest is recorded on a cash basis when NPI proceeds are received by the Trust from Whiting. NPI proceeds that Whiting remits to the Trust are based on the oil and gas production Whiting has received payment for within one month following the end of the most recent fiscal quarter. Whiting receives payment for its crude oil sales generally within 30 days following the month in which it is produced, and Whiting receives payment for its natural gas sales generally within 60 days following the month in
which it is produced. Income from net profits interest is generally a function of oil and gas revenues, lease operating expenses, production taxes and cash settlements on commodity derivatives as follows:
Revenues. Oil and natural gas revenues decreased $34.5 million or 38% in 2009 compared to 2008. Revenues are a function of average sales prices and volumes sold. In 2009, oil and gas revenues and NPI distributions were negatively impacted by a substantial decline in realized commodity prices. The average price realized for oil before the effects of hedging decreased 53% between periods, and the average price realized for natural gas before the effects of hedging decreased 54%. Partially offsetting the significant decline in commodity prices was an increase in production volumes sold between periods. Oil sales volumes increased 32% or 208 MBOE, and gas sales volumes increased 29% or 832 MMcf for the year ended December 31, 2009 as compared to 2008. These volume increases were due to the fact that there were four NPI distributions and therefore twelve months of oil and gas production during 2009 compared to only three NPI distributions, which included nine months of oil and eight months of gas production, during 2008. There were only three NPI distributions during 2008 because the NPI was conveyed effective for production from the underlying properties beginning January 1, 2008. Despite this increase in production volumes between periods, oil and gas production attributable to the underlying properties is estimated to decline at rates ranging from 9% to 11% from 2011 to 2015, based on the reserve report as of December 31, 2010.
Lease Operating Expenses. Lease operating expenses increased $6.9 million or 36% from 2008 to 2009 because there were four NPI distributions and therefore twelve months of LOE during 2009, as compared to three NPI distributions and only nine months of LOE during 2008. Lease operating expenses per BOE increased from $17.38 in 2008 to $17.96 for 2009. The 3% increase on a BOE basis was primarily caused by the timing of receipts and cash disbursements for expenditures.
Production Taxes. Production taxes are generally calculated as a percentage of oil and gas revenues before the effects of hedging. All credits and exemptions allowed in the various taxing jurisdictions are fully utilized. Production taxes during 2009 decreased $2.4 million or 38% compared to 2008, primarily due to lower oil and natural gas sales between periods. Production taxes as a percent of oil and gas revenues, however, remained constant for both 2009 and 2008 at 7.0%.
Cash Settlements on Commodity Derivatives. Whiting entered into certain costless collar hedge contracts for the benefit of the Trust prior to the conveyance. If current market prices are lower than a collar’s price floor when the cash settlement amount is calculated, Whiting receives cash proceeds from the contract counterparty. Conversely, if current market prices are higher than a collar’s price ceiling when the cash settlement amount is calculated, Whiting is required to pay the contract counterparty. Cash settlements relating to the hedges resulted in a gain of $16.7 million for the twelve months ended December 31, 2009, which had the effect of increasing average sales prices net of hedging by $14.21 per Bbl for oil and $1.26 per Mcf of gas. Cash settlements relating to the hedges resulted in a deduction of $175,949, or $0.28 per Bbl of oil, compared to 2008.
Distributable Income. For the year ended December 31, 2009, the Trust’s distributable income was $37.1 million and was based on income from net profits interest of $38.3 million less general and administrative expenses of $1.1 million and Montana state income tax withholdings of $0.2 million. This compares to distributable income of $57.0 million during 2008, which was based on income from net profits interest of $58.3 million less general and administrative expenses of $0.9 million and $0.4 million for Montana state income tax withholdings.
Results of Underlying Property Operations
Because the 2008 Trust results do not include a full 12 months of NPI distributions and related property results, the Trust is providing financial information with respect to the underlying properties for the years ended December 31, 2009 and 2008 so that investors can review complete comparative results of operations for the 2009 and 2008 fiscal periods. The underlying properties’ results of operations for the years ended December 31, 2009 and 2008 are presented on a cash basis of accounting in the table below and in the related discussion in “Comparison of Results of the Underlying Properties for the Year Ended December 31, 2009 and 2008”, and this cash basis presentation is consistent with the Trust’s 2009 and 2008 financial statements, which have been prepared on a modified cash basis. The 2009 cash basis results generally consist of crude oil sales earned from December 2008 through November 2009 but received during 2009, and natural gas sales earned from November 2008 through October 2009 but received in 2009. The 2008 cash basis results generally consist of crude oil sales earned from December 2007 through November 2008 but received during 2008, and natural gas sales earned from November 2007 through October 2008 but received in 2008.
The table below sets forth revenues and direct operating expenses, as well as operating data, relating to the underlying properties for each of the years ended December 31, 2009 and 2008. Results for 2008 include the effects of hedging activities subsequent to the April 30, 2008 conveyance. The following table also provides average sales prices, per BOE data, and capital expenditures relating to the underlying properties for each period (dollars in thousands, except per Bbl, per Mcf, and per BOE amounts):
Underlying Properties Results
(1)
The results of operations for 2009 and 2008 are presented on a cash basis of accounting.
(2)
The Trust cannot provide any assurance that future capital expenditures will be consistent with historical levels.
Comparison of Results of the Underlying Properties for the Years Ended December 31, 2009 and 2008
Revenues. Oil and natural gas revenues decreased $63.6 million or 55% from 2008 to 2009. Sales are a function of average sales prices and volumes sold. In 2009, oil and gas revenues were negatively impacted by a substantial decline in realized commodity prices. The average price realized for oil before the effects of hedging decreased 49% from 2008 to 2009, and the average price realized for natural gas before the effects of hedging decreased 56% between periods. In addition, oil sales volumes decreased 5% or 46 MBbls between periods due to normal field production decline, and gas sales volumes decreased 14% or 595 MMcf between periods also due to normal field decline. Oil and gas production attributable to the underlying properties is estimated to decline at rates ranging from 9% to 11% annually from 2011 to 2015, based on the reserve report prepared by the Trust’s independent reservoir engineers as of December 31, 2010.
Lease Operating Expenses. Lease operating expenses decreased $2.4 million or 9% from 2008 to 2009, which was consistent with the 9% decrease in overall oil and gas production. Accordingly, lease operating expenses per BOE remained consistent between periods, increasing only 0.4% from $17.23 during 2008 to $17.30 during 2009.
Production Taxes. Production taxes are generally calculated as a percentage of oil and gas revenues. Tax credits and exemptions allowed in the various taxing jurisdictions are generally utilized to their potential. Production taxes for 2009 decreased $4.3 million or 53% over the same period in 2008, primarily due to lower oil and natural gas sales. Production taxes for the year ended December 31, 2009 and 2008 were 7.2% and 6.9%, respectively, of oil and gas sales.
Cash Settlements on Commodity Derivatives. Whiting entered into certain costless collar hedge contracts on April 30, 2008 in which the rights to any future hedge payments made or received were conveyed to the Trust. Cash settlements relating to the conveyed hedges resulted in a gain of $14.3 million during the year ended December 31, 2009, which had the effect of increasing average sales prices net of hedging during 2009 by $10.16 per Bbl of oil and $1.60 per Mcf of natural gas. Cash settlements relating to these hedges resulted in a gain of $3.7 million during the year ended December 31, 2008, which had the effect of increasing average sales prices net of hedging during 2008 by $3.86 per Bbl of oil and $0.07 per Mcf of natural gas.
Excess of Revenues Over Direct Operating Expenses. Excess of revenues over direct operating expenses decreased $46.3 million from 2008 to 2009. The reasons for this decrease included a 9% decrease in equivalent volumes sold, and a 40% decrease in oil prices net of hedging and a 37% decrease in gas prices net of hedging between periods. The decreased production and pricing was partially offset by reduced lease operating expense and production taxes.
Liquidity and Capital Resources
The Trust has no source of liquidity or capital resources other than cash flows from the NPI. Other than Trust administrative expenses, including any reserves established by the Trustee for future liabilities, the Trust’s only use of cash is for distributions to Trust unitholders. Administrative expenses include payments to the Trustee and the Delaware Trustee as well as a quarterly fee to Whiting pursuant to an administrative services agreement. Each quarter, the Trustee determines the amount of funds available for distribution. Available funds are the excess cash, if any, received by the Trust from the NPI and other sources (such as interest earned on any amounts reserved by the
Trustee) that quarter, over the Trust’s expenses for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities. The Trustee may borrow funds required to pay liabilities if the Trustee determines that the cash on hand and the cash to be received are insufficient to cover the Trust’s liabilities. If the Trustee borrows funds, the Trust unitholders will not receive distributions until the borrowed funds are repaid.
Income to the Trust from the NPI is based on the calculation and definitions of “gross proceeds” and “net proceeds” contained in the conveyance, the form of which is listed as an exhibit to this report, and reference is hereby made to the conveyance for the actual definitions of “gross proceeds” and “net proceeds”.
Although capital expenditures for the testing, drilling, completion, equipping, plugging back or recompletion of any well that is a part of the underlying properties cannot be deducted from gross proceeds pursuant to the terms of the conveyance agreement, Whiting incurred capital expenditures of $1.0 million on the underlying properties during 2010 that were not deducted from gross proceeds or distributions in 2010, compared to $1.1 million in 2009 and $5.4 million in 2008, but which may have the effect of ultimately accelerating the receipt of NPI net proceeds and thereby benefiting Trust unitholders by accelerating their return on investment. The Trust cannot provide any assurance that this will occur or that future capital expenditures will be consistent with those historical levels.
On February 8, 2011, Whiting established a $1.0 million letter of credit for the Trustee in order to provide a mechanism for the Trustee to pay the operating expenses of the Trust in the unlikely event that Whiting should fail to fund the Trust in the future. This letter of credit will not be used to fund NPI distributions to unitholders.
The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust’s liquidity or the availability of capital resources.
Off-Balance Sheet Arrangements
The Trust has no off-balance sheet arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations other than the commodity hedge contracts disclosed in the section “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Commodity Hedge Contracts
The primary asset of and source of income to the Trust is the term NPI, which generally entitles the Trust to receive 90% of the net proceeds from oil and gas production from the underlying properties. Consequently, the Trust is exposed to market risk from fluctuations in oil and gas prices. Through 2012, however, the NPI is subject to commodity hedge contracts in the form of costless collars entered into by Whiting, which reduce its exposure to commodity price volatility. The Trust does not enter into derivative contracts for speculative or trading purposes.
The revenues derived from the underlying properties depend substantially on prevailing crude oil, natural gas and natural gas liquid prices. As a result, commodity prices also affect the amount of cash flow available for distribution to the Trust unitholders. Lower prices may also reduce the amount of oil, natural gas and natural gas liquids that Whiting can economically produce. Whiting sells the oil, natural gas and natural gas liquid production from the underlying properties under floating market price contracts each month. Whiting has entered into certain hedge contracts through December 31, 2012 to manage the exposure to crude oil and natural gas price volatility, which is associated with revenues generated from the underlying properties, and to achieve more predictable cash flows. However, these contracts limit the amount of cash available for distribution if prices increase above the fixed ceilings. The hedge contracts consist of costless collar arrangements placed with a single trading counterparty, JPMorgan Chase Bank National Association. Whiting cannot provide assurance that this trading counterparty will not become a credit risk in the future. No additional hedges are allowed to be placed on Trust assets.
Crude oil costless collar arrangements settle based on the average of the closing settlement price for each commodity business day in the contract period. Natural gas costless collar arrangements settle based on the closing settlement price on the second to last scheduled trading day of the month prior to delivery. In a collar arrangement, the counterparty is required to make a payment to Whiting for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. Whiting is required to make a payment to the counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price. Whiting’s crude oil and natural gas price risk management positions in collar
arrangements through December 31, 2012 (which collars have the potential to affect Whiting’s future distributions to the Trust) are as follows:
The collared hedges shown above have the effect of providing a protective floor while allowing Trust unitholders to share in upward pricing movements. Consequently, while these hedges are designed to decrease exposure to price decreases, they also have the effect of limiting the benefit of price increases beyond the ceiling. For the crude oil contracts listed above, a hypothetical $10.00 change in the NYMEX price above the ceiling price or below the floor price applied to the notional amounts would cause an aggregate change in the cash settlement payments (gains received) on all oil commodity derivatives of $9.1 million to Whiting, of which 90% would be transferred to the Trust. For the natural gas contracts listed above, a hypothetical $1.00 change in the NYMEX price above the ceiling price or below the floor price applied to the notional amounts would cause an aggregate change in the cash settlement payments (gains received) on all natural gas commodity derivatives of $3.4 million to Whiting, of which 90% would be transferred to the Trust. These hypothetical cash settlement payments (gains received) would be recognized as contracts expire in future periods through 2012.
The amounts received by Whiting from the counterparty upon settlements of these hedge contracts will reduce the operating expenses related to the underlying properties when calculating the net proceeds. However, if the hedge payments received by Whiting under the hedge contracts and other non-production revenue exceed operating expenses during a quarterly period, the ability to use such excess amounts to offset operating expenses may be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period where the hedge payments and the other non-production revenue are less than such expenses. In addition, the aggregate amounts paid by Whiting on settlement of the hedge contracts will reduce the amount of net proceeds paid to the Trust.
Item 8.
Item 8.
Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Trustee and Unit Holders of
Whiting USA Trust I
c/o The Bank of New York Mellon Trust Company, N.A., Trustee
Austin, Texas
We have audited the accompanying statements of assets, liabilities and trust corpus - modified cash basis of Whiting USA Trust I (the “Trust”) as of December 31, 2010 and 2009, and the related statements of distributable income and changes in trust corpus- modified cash basis for the years ended December 31, 2010, 2009, and 2008. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As described in Note 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America. In our opinion, such financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of Whiting USA Trust I as of December 31, 2010 and 2009, and its distributable income and changes in trust corpus for the years ended December 31, 2010, 2009, and 2008, on the comprehensive basis of accounting described in Note 2 to the financial statements.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Trust’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 15, 2011 expressed an unqualified opinion on the Trust’s internal control over financial reporting.
DELOITTE & TOUCHE LLP
Austin, Texas
March 15, 2011
WHITING USA TRUST I
Statements of Assets, Liabilities and Trust Corpus
(In thousands, except unit data)
Statements of Distributable Income
(In thousands, except distributable income per unit data)
Statements of Changes in Trust Corpus
(In thousands)
The accompanying notes are an integral part of these modified cash basis financial statements.
WHITING USA TRUST I
NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS
1.
Organization of the Trust
Formation of the Trust - Whiting USA Trust I (the “Trust”) is a statutory trust formed in October 2007 under the Delaware Statutory Trust Act, pursuant to a trust agreement (the “Trust agreement”) among Whiting Oil and Gas Corporation and Equity Oil Company, as trustors, The Bank of New York Trust Company, N.A., as Trustee (subsequently renamed The Bank of New York Mellon Trust Company, N.A., and hereinafter referred to as “Trustee”), and Wilmington Trust Company as Delaware Trustee (the “Delaware Trustee”). The initial capitalization of the Trust estate was funded by Whiting Petroleum Corporation (“Whiting”) in November 2007. Effective September 30, 2009, Equity Oil Company merged into Whiting Oil and Gas Corporation (“Whiting Oil and Gas”) with Whiting Oil and Gas as the surviving corporation. Whiting Oil and Gas, as referred to herein, is a subsidiary of Whiting and the successor to Equity Oil Company.
The Trust was created to acquire and hold a term net profits interest (“NPI”) for the benefit of the Trust unitholders pursuant to a conveyance to the Trust from Whiting Oil and Gas. The term NPI is an interest in underlying oil and natural gas properties located in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions (the “underlying properties”). The NPI is the only asset of the Trust, other than cash held for Trust expenses. These oil and gas properties include interests in 3,077 gross (373.1 net) producing oil and gas wells.
The NPI is passive in nature, and the Trustee has no management control over and no responsibility relating to the operation of the underlying properties. The NPI entitles the Trust to receive 90% of the net proceeds from the sale of production from the underlying properties. The NPI will terminate when 9.11 MMBOE have been produced and sold from the underlying properties (which amount is the equivalent of 8.20 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), and the Trust will soon thereafter wind up its affairs and terminate. As of December 31, 2010, on a cumulative accrual basis 3.90 MMBOE of the Trust’s total 8.20 MMBOE have been produced and sold and a cumulative 0.02 MMBOE have been sold in divestitures. The remaining reserve quantities are projected to be produced by November 30, 2015, based on the reserve report for the underlying properties as of December 31, 2010.
The Trustee can authorize the Trust to borrow money to pay Trust administrative or incidental expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee, Whiting, or the Delaware Trustee as a lender provided the terms of the loan are similar to the terms it would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself and make other short-term investments with the funds distributed to the Trust.
Initial Issuance of Trust Units and Net Profits Interest Conveyance - In April 2008, the registration statement on Form S-1/S-3 (Registration No. 333-147543) filed by Whiting and the Trust in connection with the initial public offering of the Trust units was declared effective by the SEC. Subsequently, the Trust issued 13,863,889 Trust units to Whiting in exchange for the conveyance of the term NPI from Whiting Oil and Gas, as discussed above. Immediately thereafter, Whiting completed an initial public offering of units of beneficial interest in the Trust,
WHITING USA TRUST I
NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS - (Continued)
selling 11,677,500 Trust units to the public. Whiting retained an ownership in 2,186,389 Trust units, or 15.8% of the total Trust units issued and outstanding.
2.
Summary of Significant Accounting Policies
Term Net Profits Interest - The Trust uses the modified cash basis of accounting to report Trust receipts from the term NPI and payments of expenses incurred. The actual cash distributions to the Trust are made based on the terms of the conveyance that created the Trust’s NPI. The term NPI entitles the Trust to receive revenues (oil, gas and natural gas liquid sales) less expenses (the amount by which all royalties, lease operating expenses including well workover costs, production and property taxes, payments made by Whiting to the hedge counterparty upon settlements of hedge contracts, maintenance expenses, post-production costs including plugging and abandonment, and producing overhead, exceed hedge payments received by Whiting under hedge contracts and other non-production revenue) of the underlying properties multiplied by 90% (term NPI percentage). Actual cash receipts may vary due to timing delays of cash receipts from the property operators or purchasers and due to wellhead and pipeline volume balancing agreements or practices.
Modified Cash Basis of Accounting - The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust’s assets, liabilities, Trust corpus, earnings and distributions, as follows:
a) Income from net profits interest is recorded when NPI distributions are received by the Trust;
b) Distributions to Trust unitholders are recorded when paid by the Trust;
c) Trust general and administrative expenses (which include the Trustees’ fees as well as accounting, engineering, legal, and other professional fees) and are recorded when paid;
d) Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under GAAP;
e) Amortization of the investment in net profits interest is calculated based on the units-of- production method. Such amortization is charged directly to Trust corpus and does not affect cash earnings; and
f) The Trust evaluates impairment of the investment in net profits interest by comparing the undiscounted cash flows expected to be realized from the investment in net profits interest to the NPI carrying value. If the expected future undiscounted cash flows are less than the carrying value, the Trust recognizes an impairment loss for the difference between the carrying value and the estimated fair value of the investment in net profits interest. At December 31, 2010 and 2009, the Trustee believes no such impairment has occurred. The determination of whether the NPI is impaired requires a significant amount of judgment by the Trustee and is based on the best information available to the Trustee at the time of the evaluation. If market conditions deteriorate, write-downs could be required in the future.
WHITING USA TRUST I
NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS - (Continued)
While these statements differ from financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues and distributions is considered to be the most meaningful because quarterly distributions to the Trust unitholders are based on net cash receipts. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by FASB ASC topic Extractive Activities - Oil and Gas: Financial Statements of Royalty Trusts.
Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with GAAP, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues were received or expenses were paid. Because the Trust’s financial statements are prepared on the modified cash basis as described above, however, most accounting pronouncements are not applicable to the Trust’s financial statements.
Cash and Short-Term Investments. Cash and short-term investments include all highly liquid short-term investments with original maturities of three months or less.
Concentration of Credit Risk. The underlying properties from which the NPI is derived principally sell their oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. The following table presents the percentages of oil and natural gas sales from the underlying properties sold to each significant purchaser for the years ended December 31, 2010, 2009 and 2008:
The loss of one or all of these purchasers does not present a material risk because there is significant competition among purchasers of crude oil and natural gas in the areas of the underlying properties, and if they were to lose one or both of their largest purchasers, several entities could purchase crude oil and natural gas produced from the underlying properties with little or no interruption to their business.
The underlying properties’ oil and gas revenues, which are included in the NPI net proceeds computation, are subject to commodity hedge contracts through December 31, 2012. The hedge contracts consist of costless collar arrangements that are placed with a single trading counterparty, JPMorgan Chase Bank National Association, and there is no assurance that this trading counterparty will not become a credit risk in the future.
Use of Estimates. The preparation of financial statements requires estimates and assumptions that affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Significant estimates affecting these financial statements include estimates of proved oil and gas reserves, which are used to compute the Trust’s amortization of net profits interest and its impairment assessments. Although the Trustee believes that these estimates are reasonable, actual results could differ from those estimates.
WHITING USA TRUST I
NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS - (Continued)
Recent Accounting Pronouncements. In December 2008, the SEC issued Modernization of Oil and Gas Reporting: Final Rule, which published the final rules and interpretations updating its oil and gas reporting requirements. The final rule includes updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determine reserves in that companies must use a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months that make up the reporting period. The Trust adopted the new rules effective December 31, 2009, and as a result (i) prepared its reserve estimates as of December 31, 2009 and 2010 based on the new reserve definitions, (ii) estimated its December 31, 2009 and 2010 reserve quantities using the 12-month average price and (iii) included additional disclosures in Item 2 of this Annual Report on Form 10-K, as required by the new rule. The adoption of this new rule, however, had no impact on the Trust’s statements of assets, liabilities and trust corpus, statements of distributable income, or statements of changes in trust corpus.
In January 2010, the FASB issued Accounting Standards Update No. 2010-03, Oil and Gas Reserve Estimation and Disclosures (“ASU 2010-03”), which provides amendments to FASB ASC topic Extractive Activities-Oil and Gas. The objective of ASU 2010-03 is to align the oil and gas reserve estimation and disclosure requirements of the FASB ASC with the requirements in the SEC’s Modernization of Oil and Gas Reporting: Final Rule. The Trust adopted ASU 2010-03 effective December 31, 2009, and as a result (i) has estimated its December 31, 2009 and 2010 reserve quantities using the 12-month average price, (ii) has prepared its reserve estimates as of December 31, 2009 and 2010 based on the new and amended reserve definitions in ASU 2010-03 that conform to the SEC’s revised reserve definitions, and (iii) has calculated its future cash inflows, which are incorporated into the standardized measure of discounted future net cash flows, using 12-month average rather than year-end oil and gas prices. The adoption of ASU 2010-03, however, had no impact on the Trust’s statements of assets, liabilities and trust corpus, statements of distributable income, or statements of changes in trust corpus.
3.
Investment in Net Profits Interest
Whiting Oil and Gas conveyed the NPI to the Trust in exchange for 13,863,889 Trust units. The investment in net profits interest was recorded at the historical cost of Whiting on April 30, 2008, the date of conveyance, and was determined to be $123.6 million, of which $111.2 million (90% of the NPI) was attributed to the Trust. Accumulated amortization as of December 31, 2010 and 2009 was $49.2 million and $31.9 million, respectively.
WHITING USA TRUST I
NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS - (Continued)
4.
Income from Net Profits Interest
The Trust received income from net profits interest as follows (dollars in thousands):
(a)
Because of the one-month interval between the time crude oil volumes are produced and the receipt of oil sales proceeds by Whiting, oil sales for the year ended December 31, 2010 (consisting of Whiting’s February, May, August and November 2010 NPI distributions to the Trust) generally represent crude oil production from October 2009 through September 2010.
(b)
Because of the two-month interval between the time natural gas volumes are produced and the receipt of gas sales proceeds by Whiting, natural gas sales for the year ended December 31, 2010 (consisting of Whiting’s February, May, August and November 2010 NPI distributions to the Trust) generally represent gas production from September 2009 through August 2010.
(c)
Because of the one-month interval between the time crude oil volumes are produced and the receipt of oil sales proceeds by Whiting, oil sales for the year ended December 31, 2009 (consisting of Whiting’s February, May, August and November 2009 NPI distributions to the Trust) generally represent crude oil production from October 2008 through September 2009.
(d)
Because of the two-month interval between the time natural gas volumes are produced and the receipt of gas sales proceeds by Whiting, natural gas sales for the year ended December 31, 2009 (consisting of Whiting’s February, May, August and November 2009 NPI distributions to the Trust) generally represent gas production from September 2008 through August 2009.
(e)
Because of the one-month interval between the time crude oil volumes are produced and the receipt of oil sales proceeds by Whiting, oil sales for the year ended December 31, 2008 (consisting of Whiting’s May, August and November 2008 NPI distributions to the Trust) generally represent crude oil production from January 2008 through September 2008.
WHITING USA TRUST I
NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS - (Continued)
(f)
Because of the two-month interval between the time natural gas volumes are produced and the receipt of gas sales proceeds by Whiting, natural gas sales for the year ended December 31, 2008 (consisting of Whiting’s May, August and November 2008 NPI distributions to the Trust) generally represent gas production from January 2008 through August 2008.
5.
Income Taxes
The Trust is a grantor trust and therefore is not subject to federal income taxes. Accordingly, no recognition has been given to federal income taxes in the Trust’s financial statements or in the Trust’s standardized measure of discounted future net cash flows. The Trust unitholders are treated as the owners of Trust income and corpus, and the entire federal taxable income of the Trust is reported by the Trust unitholders on their respective tax returns.
For Montana state income tax purposes, Whiting must withhold from the NPI payable to the Trust, an amount equal to 6% of the net amount payable to the Trust from the sale of oil and gas in Montana. Whiting withheld $0.2 million related to Montana state income taxes for each of the years ended December 31, 2010 and 2009, and withheld $0.4 million in Montana income taxes for the year ended December 31, 2008. For North Dakota, Oklahoma, Arkansas, Michigan, New Mexico, Alabama, Louisiana, Colorado, Kansas, Utah and Mississippi, neither the Trust nor Whiting is withholding the income tax due such states on distributions made to an individual resident or nonresident Trust unitholder, as long as the Trust is taxed as a grantor trust under the Internal Revenue Code.
6.
Distribution to Unitholders
Actual cash distributions to the Trust unitholders depend on the volumes of and prices received for oil, natural gas and natural gas liquids produced from the underlying properties, among other factors. Quarterly cash distributions during the term of the Trust are made by the Trustee generally no later than 60 days following the end of each quarter (or the next succeeding business day) to the Trust unitholders of record on the 50th day following the end of each quarter. Such amounts equal the excess, if any, of the cash received by the Trust during the quarter, over the expenses of the Trust paid during such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for future expenses of the Trust.
7.
Related Party Transactions
Capital Expenditures - During the years ended December 31, 2010, 2009 and 2008, Whiting incurred $1.0 million, $1.1 million and $5.4 million, respectively, of capital expenditures on the underlying properties, which are costs net to Whiting’s interest in the wells, related to the drilling and completing of oil and gas wells, capital workovers, facility upgrades and well recompletions performed to secure production from new horizons. These expenditures may have the effect of ultimately increasing current and future period NPI net proceeds and thereby benefiting the Trust unitholders by accelerating their return on investment. Pursuant to the terms of the conveyance agreement, however, Whiting did not deduct, nor will it deduct in the future, such capital expenditures from the NPI
WHITING USA TRUST I
NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS - (Continued)
gross proceeds or related distributions to the Trust. The Trust cannot provide any assurance that this will occur or that future capital expenditures will be consistent with historical levels.
Operating Overhead - Pursuant to the terms of the applicable joint operating agreements, Whiting deducts from the gross proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally, for those underlying properties for which Whiting is the operator but for which there is no operating agreement, Whiting deducts from the gross proceeds an overhead fee calculated in the same manner Whiting allocates overhead to other similarly owned properties, as is customary in the oil and gas industry. Operating overhead activities include various engineering, legal, and administrative functions. The fee is adjusted annually pursuant to COPAS guidelines and will increase or decrease each year based on changes in the year-end index of average weekly earnings of crude petroleum and natural gas workers. The following table presents the Trust’s portion of these overhead charges for the years ended December 31, 2010, 2009 and 2008 (dollars in thousands except per well data):
Administrative Services Fee - Under the terms of the administrative services agreement, the Trust pays a quarterly administration fee of $50,000 to Whiting 60 days following the end of each calendar quarter. General and administrative expenses in the Trust’s statements of distributable income for the year ended December 31, 2010 and 2009 each include $200,000 for quarterly administrative fees paid to Whiting, while the year ended December 31, 2008 includes $150,000 of such administrative fees.
Trustee Administrative Fee - Under the terms of the Trust agreement, the Trust pays an annual administrative fee to the Trustee of $160,000, paid in four quarterly installments of $40,000 each and is billed in arrears. General and administrative expenses in the Trust’s statements of distributable income for the years ended December 31, 2010 and 2009 each include $160,000 for administrative fees paid to the Trustee, while the year ended December 31, 2008 includes $80,000 of such administrative fees.
8.
Subsequent Events
The Trustee has evaluated subsequent events through the date that these financial statements were issued. The following information is disclosed as a nonrecognized subsequent event:
On March 1, 2011, a distribution of $0.667847 per Trust unit was paid to Trust unitholders owning Trust units as of February 21, 2011. The distribution consisted of net cash proceeds of $9.3 million paid by Whiting to the Trust, which included cash receipts of $1.4 million (90% of $1.6 million) for commodity derivative contracts settled from October 1, 2010 through December 31, 2010, less a provision of $250,000 for estimated Trust expenses and $57,719 for Montana state income tax withholdings.
WHITING USA TRUST I
NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS - (Continued)
On February 8, 2011, Whiting established a $1.0 million letter of credit for the Trustee in order to provide a mechanism for the Trustee to pay the operating expenses of the Trust in the unlikely event that Whiting should fail to fund the Trust in the future. This letter of credit will not be used to fund NPI distributions to unitholders.
9.
Supplemental Oil and Gas Reserve Information (Unaudited)
Estimates of proved reserves attributable to the Trust and the related valuations were based 100% on reports prepared by the Trust’s independent petroleum engineers Cawley, Gillespie & Associates, Inc. Proved reserve estimates included herein conform to the definitions prescribed by the FASB and SEC. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.
As of December 31, 2010, all of the underlying properties’ oil and gas reserves are attributable to properties within the United States. Proved reserves attributable to the Trust and related standardized measure valuations are prepared on an accrual basis for all periods presented, which is the basis on which Whiting and the underlying properties maintain their production records and is different from the cash basis on which the Trust production records are computed.
WHITING USA TRUST I
NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS - (Continued)
The following is a summary of the changes in quantities of proved oil and gas reserves attributable to the Trust for the years ended December 31, 2008, 2009 and 2010:
(1)
Reserves related to the underlying properties on a full economic life basis as of January 1, 2008 and as of December 31, 2008, 2009 and 2010 were 13.9 MMBOE, 9.0 MMBOE, 9.3 MMBOE and 12.6 MMBOE, respectively.
(2)
During 2010 and 2009, Whiting received sale proceeds of $3,172 and $16,884, respectively, in exchange for its divestiture of Trust properties that held 1 MBOE and 21 MBOE, respectively, of proved reserves. Whiting includes all such proceeds from Trust property divestitures in its NPI distributions to the Trust.
WHITING USA TRUST I
NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS - (Continued)
(3)
These tables do not include quantities of proved undeveloped reserve as of January 1, 2008 or as of December 31, 2008, 2009 and 2010 because the underlying properties consist of mature producing properties that are generally fully developed. Technical studies have not identified any drilling locations that meet the criteria of proved undeveloped reserves, nor has any future capital been committed for the development of proved undeveloped reserves on the underlying properties.
(4)
Oil includes natural gas liquids.
Notable changes in proved reserves for the year ended December 31, 2010 included:
•
Revisions to previous estimates. In 2010, revisions to previous estimates increased proved reserves by a net amount of 32 MBOE. Included in these revisions were 1.4 Bcf of upward adjustments to natural gas primarily due to higher gas prices of $4.17 per Mcf in reserve estimates at December 31, 2010, as compared to gas prices of $3.15 per Mcf at December 31, 2009. This upward revision in natural gas was almost entirely offset, however, by 201 MBbl of downward adjustments to crude oil reserves. Crude oil reserves declined in 2010 primarily due to adjustments to production accruals, which decreases were partially offset by higher oil prices of $68.77 per Bbl in reserve estimates at December 31, 2010, as compared to $51.58 per Bbl of oil at December 31, 2009.
Notable changes in proved reserves for the year ended December 31, 2009 included:
•
Revisions to previous estimates. In 2009, revisions to previous estimates decreased proved reserves by a net amount of 40 MBOE. Included in these revisions were 3.8 Bcf of downward adjustments to natural gas primarily due to lower gas prices of $3.15 per Mcf in reserve estimates at December 31, 2009, as compared to gas prices of $4.96 per Mcf at December 31, 2008. This downward revision in natural gas was almost entirely offset, however, by 597 MBbl of upward adjustments to crude oil reserves primarily due to higher oil prices of $51.58 per Bbl in reserve estimates at December 31, 2009, as compared to $36.27 per Bbl of oil at December 31, 2008.
Notable changes in proved reserves for the year ended December 31, 2008 included:
•
Revisions to previous estimates. In 2008, revisions to previous estimates decreased proved reserves by a net amount of 47 MBOE. Included in these revisions were 594 MBbl of downward adjustments to crude oil primarily due to lower oil prices of $36.27 per Bbl in reserve estimates at December 31, 2008, as compared to $86.17 per Bbl of oil at December 31, 2007, causing a decrease in the estimated economic life of many of the oil wells. This downward revision in crude oil reserves was almost entirely offset, however, by 3.3 Bcf of net upward adjustments to natural gas reserve quantities. This is because the loss of oil reserves from the price-affected oil wells extended the estimated Trust termination date at year-end 2008 by four years to December 31, 2021, and the shorter lives of the oil wells were then generally replaced by production from natural gas wells over the extended life of the Trust. As a result, there was a change in the relative composition of future oil and gas production leading to the ultimate recovery of the Trust’s 8.20 MMBOE, with the natural gas reserves increase of 3.3 Bcf generally offsetting the 594 MBbl decrease in oil reserves.
WHITING USA TRUST I
NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS - (Continued)
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with the provisions of FASB ASC topic Extractive Activities - Oil and Gas. Future cash inflows as of December 31, 2010 and 2009 were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended December 31, 2010 and 2009) to estimated future production. Future cash inflows as of December 31, 2008, however, were computed by applying prices at year end to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming the continuation of existing economic conditions.
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves attributable to the Trust is as follows (dollars in thousands):
(1)
No provision for federal or state income taxes has been provided because taxable income is passed through to the unitholders of the Trust.
WHITING USA TRUST I
NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS - (Continued)
The changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves attributable to the Trust are as follows (dollars in thousands):
Future cash inflows included in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves incorporate weighted average sales prices (inclusive of adjustments for quality and location) in effect at December 31, 2010, 2009 and 2008 as follows:
WHITING USA TRUST I
NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS - (Continued)
10.
Selected Quarterly Financial Data (Unaudited)
(1)
Dollars in thousands, except for distributions per unit.
******
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A.
Controls and Procedures.
Evaluation of Disclosure Controls and Procedures. The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and regulations promulgated by the SEC. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by Whiting to The Bank of New York Mellon Trust Company, N.A., as Trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, the Trustee carried out an evaluation of the Trustee’s disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.
Due to the contractual arrangements of (i) the Trust agreement and (ii) the conveyance of the NPI, the Trustee relies on (A) information provided by Whiting, including historical operating data, plans for future operating and capital expenditures, reserve information and information relating to projected production, and (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers. See Risk Factors “The Trust and the Trust unitholders have no voting or managerial rights with respect to the underlying properties. As a result, Trust unitholders have no ability to influence the operation of the underlying properties” and “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report on Form 10-K, for a description of certain risks relating to these arrangements and reliance on information when reported by Whiting to the Trustee and recorded in the Trust’s results of operation.
Changes in Internal Control over Financial Reporting. During the quarter ended December 31, 2010, there has been no change in the Trustee’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trustee’s internal control over financial reporting relating to the Trust. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of Whiting.
Trustee’s Annual Report on Internal Control Over Financial Reporting. A registrant’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A registrant’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the registrant; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the registrant are being made only in accordance with authorizations of management and directors of the registrant; and (iii) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the registrants assets that could have a material effect on the financial statements.
The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities and Exchange Act of 1934, as amended. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control - Integrated Framework, the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2010.
Deloitte & Touche, LLP, the Trust’s independent registered public accounting firm that audited the financial statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Trust’s internal control over financial reporting.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
March 15, 2011
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Trustee and Unit Holders of
Whiting USA Trust I
c/o The Bank of New York Mellon Trust Company, N.A., Trustee
Austin, Texas
We have audited the internal control over financial reporting of Whiting USA Trust I (the “Trust”) as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Trustee is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Trustee’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Trust’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A trust’s internal control over financial reporting is a process designed by, or under the supervision of, the trust’s trustee, and effected by the trustee and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the comprehensive basis of accounting described in Note 2 to the financial statements. A trust’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the comprehensive basis of accounting described in Note 2 of the financial statements, and that receipts and expenditures of the trust are being made only in accordance with authorization of the Trustee; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the trust’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper trustee override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2010 of the Trust and our report dated March 15, 2011 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Trust’s basis of accounting.
DELOITTE & TOUCHE LLP
Austin, Texas
March 15, 2011
Item 9B.
Item 9B.
Other Information.
None.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance.
The Trust has no directors or executive officers. The Trustee is a corporate trustee that may be removed by the affirmative vote of the holders of not less than a majority of the outstanding Trust units at a meeting at which a quorum is present.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act of 1934 requires the holders of more than 10 percent of the Trust units to file with the SEC reports regarding their ownership and changes in ownership of the Trust units. The Trustee is not aware of any 10 percent unitholder having failed to comply with all Section 16(a) filing requirements in 2010.
Audit Committee and Nominating Committee
Because the Trust does not have a board of directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.
Code of Ethics
The Trust does not have a principal executive officer, principal financial officer, principal accounting officer or controller and, therefore, has not adopted a code of ethics applicable to such persons. However, employees of the Trustee must comply with the bank’s code of ethics.
Item 11.
Item 11.
Executive Compensation.
During the year ended December 31, 2010 the Trustee received administrative fees from the Trust in the amount of $160,000. The Trust does not have any executive officers, directors or employees. Because the Trust does not have a board of directors, it does not have a compensation committee.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
(a) Security Ownership of Certain Beneficial Owners.
Based on filings with the SEC, the Trustee is not aware of any holders of 5% or more of the units except as set forth below. The following information has been obtained from filings with the SEC on Schedule 13G.
(b) Security Ownership of Management.
Not applicable.
(c) Changes in Control.
The registrant knows of no arrangement, including any pledge by any person of securities of the registrant or any of its parents, the operation of which may at a subsequent date result in a change of control of the registrant.
Item 13.
Item 13.
Certain Relationships, Related Transactions and Director Independence.
Letter of Credit
On February 8, 2011, Whiting established a $1.0 million letter of credit for the Trustee in order to provide a mechanism for the Trustee to pay the operating expenses of the Trust in the unlikely event that Whiting should fail to fund the Trust in the future. This letter of credit will not be used to fund NPI distributions to unitholders.
Capital Expenditures
During the year ended December 31, 2010, Whiting incurred $1.0 million of capital expenditures on the underlying properties, which are costs net to Whiting’s interest in the wells, related to the drilling and completing of oil and gas wells, capital workovers, facility upgrades and well recompletions performed to secure production from new horizons. These expenditures may have the effect of ultimately increasing current and future period NPI net proceeds and thereby benefiting the Trust unitholders by accelerating their return on investment. Pursuant to the terms of the conveyance agreement, however, Whiting did not deduct, nor will it deduct in the future, such capital expenditures from the NPI gross proceeds or related distributions to the Trust.
Operating Overhead
Pursuant to the terms of the applicable operating agreements, Whiting deducts from the gross proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally, for those underlying properties for which Whiting is the operator but for which there is no operating agreement, Whiting deducts from the gross proceeds an overhead fee calculated in the same manner Whiting
allocates overhead to other similarly owned properties, as is customary in the oil and gas industry. The operating overhead activities include various engineering, legal, and administrative functions. For the year ended December 31, 2010, the Trust’s portion of the monthly charge totaled $1.8 million and averaged $415 per month per active operated well. The fee is adjusted annually pursuant to COPAS guidelines and will increase or decrease each year based on changes in the year-end index of average weekly earnings of crude petroleum and natural gas workers.
Administrative Services
Under the terms of the administrative services agreement, the Trust pays a quarterly administration fee of $50,000 to Whiting 60 days following the end of each calendar quarter. General and administrative expenses in the Trust’s statements of distributable income for the year ended December 31, 2010 include $200,000 for quarterly administrative fees paid to Whiting.
The administrative services agreement will expire upon the termination of the net profits interest unless earlier terminated by mutual agreement of the Trustee and Whiting.
Trustee Administration Fee
Under the terms of the Trust agreement, the Trust pays an annual administrative fee to the Trustee of $160,000, paid in four quarterly installments of $40,000 each and is billed in arrears. General and administrative expenses in the Trust’s statements of distributable income for the year ended December 31, 2010 include $160,000 for quarterly administrative fees paid to the Trustee.
Registration Rights
The Trust entered into a registration rights agreement with Whiting in connection with Whiting’s conveyance to the Trust of the net profits interest. In the registration rights agreement, the Trust agreed, for the benefit of Whiting and any transferee of its Trust units (each, a “holder”), to register the Trust units it holds. Specifically, the Trust agreed:
•
to use its reasonable best efforts to file a registration statement, including, if so requested, a shelf registration statement, with the SEC as promptly as practicable following receipt of a notice requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable Trust units;
•
to use its reasonable best efforts to cause the registration statement or shelf registration statement to be declared effective under the Securities Act as promptly as practicable after the filing thereof; and notice requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable Trust units;
•
to continuously maintain the effectiveness of the registration statement under the Securities Act for 90 days (or for three years if a shelf registration statement is requested) after the effectiveness thereof or until the Trust units covered by the registration statement have been sold pursuant to such registration statement or until all registrable Trust units:
•
have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities;” or
•
have been sold in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee of the Trust units.
The holders will have the right to require the Trust to file up to three registration statements and will have piggyback registration rights in certain circumstances.
In connection with the preparation and filing of any registration statement, Whiting will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the Trust, which will be borne by the Trust, and any underwriting discounts and commissions, which will be borne by the seller of the Trust units.
Director Independence
The Trust does not have a board of directors and therefore no determination been made relative to director independence.
Item 14.
Item 14.
Principal Accountant Fees and Services.
The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustee. The Trustee has appointed Deloitte & Touche, LLP, the member firm of Deloitte & Touche Tohmatsu, and their respective affiliates (collectively “Deloitte”) as the independent registered public accounting firm to audit the Trust’s financial statements for the fiscal year ended December 31, 2010. During fiscal 2010 and 2009, Deloitte served as the Trust’s independent registered public accounting firm.
The following table presents the aggregate fees billed to the Trust for the fiscal years ended December 31, 2010 and 2009 by Deloitte (dollars in thousands):
(1)
Fees for audit services in 2010 and 2009 consisted of the audit of the Trust’s annual financial statements and reviews of the Trust’s quarterly financial statements.
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules
(a)(1) Financial Statements
The following financial statements are set forth under “Financial Statements and Supplementary Data” in Item 8 of this Annual Report on Form 10-K on the pages indicated:
(a)(2) Schedules
Schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.
(a)(3) Exhibits
See Exhibit Index.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
WHITING USA TRUST I
By
THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.
By:
/s/ MIKE ULRICH
Mike Ulrich
Vice President
March 15, 2011
The Registrant, Whiting USA Trust I, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that such function exists pursuant to the terms of the Trust agreement under which it serves.
Appendix 1
Cawley, Gillespie & Associates, Inc.
PETROLEUM CONSULTANTS
Whiting USA Trust I
1700 Broadway, Suite 2300
Denver, Colorado 80290-2300
Re:
Evaluation Summary - SEC Price
Whiting USA Trust I Interests
Proved Producing Reserves
Certain Properties Located in Various States
As of December 31, 2010
Pursuant to the Guidelines of the Securities and
Exchange Commission for Reporting Corporate
Reserves and Future Net Revenue
A-1
Whiting USA Trust I
January 10, 2011
Gentlemen:
As requested, we are submitting our estimates of proved producing reserves and forecasts of economics attributable to the underlying properties, from which a net profits interest has been formed and conveyed by Whiting Petroleum Corporation to the Whiting USA Trust I. These certain oil and gas properties are located in North Dakota, Texas, Oklahoma, Arkansas, Montana, Wyoming, Michigan, New Mexico, Alabama, Louisiana, Colorado, Kansas, Utah and Mississippi. Also included in the table below are the proved reserves attributable to the same underlying properties estimated to be produced by November 30, 2015, which is the estimated date of termination for Whiting USA Trust I. This report, completed January 10, 2011 covers 100% of the proved producing reserves estimated for Whiting USA Trust I. This report includes results for an SEC pricing scenario. The results of this evaluation are presented in the accompanying tabulations, with a composite summary presented below:
*
Calculated based on an energy equivalent that one bbl of crude oil equals six Mcf of natural gas and one Bbl of crude oil equals one Bbl of natural gas liquids.
The discounted cash flow value shown in the previous table should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc.
A-2
Whiting USA Trust I
January 10, 2011
Hydrocarbon Pricing
As requested for the SEC scenario, initial WTI spot oil and Henry Hub Gas Daily prices of $79.43 per bbl and $4.38 per MMBtu, respectively, were adjusted individually to WTI posted pricing at $76.16 per bbl and Houston Ship Channel pricing at $4.30 per MMBtu, as of December 31, 2010. Prices were not escalated in the SEC scenario. Oil price differentials, gas price differentials and heating values were applied as furnished by your office.
Expenses and Taxes
Lease operating expenses and Ad Valorem tax values were forecast as provided by your office. Lease operating expenses were held constant in accordance with SEC guidelines. Severance tax rates were applied at normal state percentages of oil and gas revenue.
Miscellaneous
An on-site field inspection of the properties has not been performed. The mechanical operation or conditions of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included.
The proved reserve classifications used conform to the criteria of the Securities and Exchange Commission (“SEC”). The estimates were prepared based on the definitions and regulations contained in the United States Securities and Exchange Commission Modernization of Oil and Gas Reporting; Final Rule, Title 17 CFR parts 210, 211 et al. Released January 14, 2009 in the Federal Register. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties in effect as noted herein. The possible effects of changes in legislation or other federal or state restrictive actions have not been considered. All reserve estimates represent our best judgment based on data available at the time of preparation, and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.
The reserve estimates were based on interpretations of factual data furnished by your office. We have used all methods and procedures as we considered necessary under the circumstances to prepare the report. We believe that the assumptions, data, methods and procedures were appropriate for the purpose served by this report. Production data, gas prices, gas price differentials, expense data, tax values and ownership interests were also supplied by you and were accepted as furnished. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data.
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Whiting USA Trust I
January 10, 2011
The professional qualifications of the undersigned, the technical person primarily responsible for the preparation of this report, are included as an attachment to this letter.
Yours very truly,
Robert D. Ravnaas, P.E.
Executive Vice President
Cawley, Gillespie & Associates
Texas Registered Engineering Firm
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Cawley, Gillespie & Associates, Inc.
PETROLEUM CONSULTANTS
1000 LOUISIANA STREET, SUITE 625 HOUSTON,
TEXAS 77002-5008
713-651-9944
FAX 713-651-9980
306 WEST SEVENTH STREET,
SUITE 302 FORT WORTH, TEXAS 76102-4987
817-336-2461
FAX 817-877-3728
9601 AMBERGLEN BLVD.,
SUITE 117 AUSTIN,
TEXAS 78729-1106
512-249-7000
FAX 512-233-2618
Professional Qualifications of Robert D. Ravnaas, P.E.
Executive Vice President of Cawley, Gillespie & Associates
Mr. Ravnaas has been a Petroleum Consultant for Cawley, Gillespie & Associates (CG&A) since 1983, and became Executive Vice President in 1999. He has completed numerous field studies, reserve evaluations and reservoir simulation, waterflood design and monitoring, unit equity determinations and producing rate studies. He has testified before the Texas Railroad Commission in unitization and field rules hearings. Prior to CG&A he worked as a Production Engineer for Amoco Production Company. Mr. Ravnaas received a B.S. with special honors in Chemical Engineering from the University of Colorado at Boulder, and a M.S. in Petroleum Engineering from the University of Texas at Austin. He is a registered professional engineer in Texas, No. 61304, and a member of the Society of Petroleum Engineers (SPE), the Society of Petroleum Evaluation Engineers, the American Association of Petroleum Geologists and the Society of Professional Well Log Analysts.
INDEX TO EXHIBITS
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Filed Herewith