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 (512) 236-6599.
The Trust makes copies of its reports under the Exchange Act available at http://whx.investorhq.businesswire.com. The Trust’s filings under the Exchange Act are also available electronically from the website maintained by the SEC at http://www.sec.gov. In addition, the Trust will provide electronic and paper copies of its recent filings free of charge upon request to the Trustee.
As of December 31, 2007, the Trust had no assets other than a de minimis cash balance from its initial capitalization and had conducted no operations other than organizational activities. In 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 NPI by Whiting Oil and Gas. The NPI, which terminated effective January 28, 2015, represented the right of 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 were located in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions. 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 terminated effective January 28, 2015 as a result of 9.11 MMBOE (which amount is equivalent to 8.20 MMBOE attributable to the NPI) having been produced and sold from the underlying properties. As previously disclosed in the press release issued by the Trust on March 10, 2015, there will be no payment made to unitholders for the final Trust distribution period due to the net profits interest generating a $133,718 net loss from January 1, 2015 through the net profits interest termination date of January 28, 2015 (the “final distribution period”).
Given the time lag between when production is sold and the related revenues are received and expenses relating thereto are paid, on or about August 31, 2015, the Trust may make a distribution if, after the receipt of revenues and payment of expenses, there are any positive net proceeds to distribute after recovery of the $133,718 net loss generated during the final distribution period (the “true-up distribution”). Unitholders of record on March 19, 2015 will be entitled to such distribution, if any. If the true-up calculation results in an increased net loss, the Trust will not be responsible for repayment of any portion of the net loss. As of March 19, 2015, 99.9% of the Trust’s total 13,863,889 units outstanding were held by Cede & Co., which is the DTC’s nominee, and Whiting as the official unitholders of record. Therefore, the March 19, 2015 record date, as it relates to any potential true-up distribution, is only applicable to unitholders of record such as Cede & Co. and Whiting, and the ex-date actually determines which street name holders will be eligible to receive a true-up distribution, if any such distribution is made by the Trust. It is likely that there may not be any true-up distribution or, if there is one, it is not likely to be significant. After any true-up distribution or determination that no such payment will be made, the Trust will soon thereafter wind up its affairs and terminate. The Trust units are expected to be canceled during the third quarter of 2015, and except for the slight possibility of a minor true-up distribution as discussed above, the Trust will not make any future distributions whatsoever. Additionally, as previously announced, the stock transfer books for the Trust were closed at the close of business on March 19, 2015.
The Trust units ceased trading on the New York Stock Exchange (the “NYSE”) effective before market open on February 17, 2015. The NYSE informed the Trust that the Trust was not in compliance with the NYSE’s continued listing standards, which require that the average closing price of the Trust units cannot be less than $1.00 per share over a period of 30 consecutive trading days. The Trust units transitioned to OTC Pink, operated by OTC Markets Group, effective with the opening of trading on February 17, 2015. The Trust can provide no assurance that any trading market for the Trust units will exist on OTC Pink or that current trading levels will be sustained or not diminish.
As of December 31, 2014, on a cumulative accrual basis 8.11 MMBOE (99%) of the Trust’s total 8.20 MMBOE had been produced and sold and a cumulative 0.02 MMBOE had been divested. Further detail on the reserves is provided herein under the section titled “Properties-Description of 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, 2014, which we refer to as the “reserve report.” See “Risk Factors” in Item 1A
Item 1A. Risk Factors
The NPI terminated effective January 28, 2015, the Trust announced on March 10, 2015 there would be no final distribution to record holders as of March 19, 2015, and the Trust is precluded from acquiring other oil and natural gas properties. Consequently, as required by the Trust agreement, the Trust is in the process of winding up and terminating, which will result in the cancelation of the Trust units. If the Trust units are trading at a price in excess of any true-up distribution that may be reasonably expected to be made by the Trust (and no distribution is likely), the trading price of the Trust units is likely to include one or more abrupt decreases.
The NPI terminated effective January 28, 2015, and the Trust announced that there would be no final distribution to record holders as of March 19, 2015 for the final distribution period. 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. Therefore, the Trust is not permitted to acquire other oil and natural gas properties. As a result of the termination of the NPI, the Trust is in the process of winding up and terminating, which includes the cancelation of the Trust units. The cancelation of the Trust units is expected to occur during the third quarter of 2015.
If the Trust units are trading at a price in excess of any true-up distribution amount that may reasonably be expected to be made by the Trust, the trading price of the Trust units is likely to include one or more abrupt decreases. The market price of the Trust units may be affected by factors other than expectations regarding the possibility of any true-up distribution amount. However, because the Trust is unlikely to make any further distribution, and because any distribution the Trust may make is likely to be insignificant, the Trust units have little or no intrinsic value.
The Trust units have been delisted from the New York Stock Exchange. It will likely be more difficult for unit holders to sell the Trust units or to obtain accurate quotations of the Trust units.
Effective before market open on February 17, 2015, the Trust units were delisted from the NYSE, and on the same day, trading of the Trust units commenced on OTC Pink, operated by OTC Markets Group, under the trading symbol “WHXT.” The Trust can provide no assurance that any trading market for the Trust units will exist on OTC Pink or that current trading levels will be sustained or not diminish.
Securities traded on the over-the-counter markets are typically less liquid than stocks that trade on the NYSE. Trading on the over-the-counter market may negatively affect the trading price and liquidity of the Trust units and could result in larger spreads in the bid and ask prices for Trust units. Unit holders may find it difficult to resell their Trust units due to the delisting.
The Trust is managed by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.
The business and affairs of the Trust are administered by the Trustee. The voting rights of a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The Trust agreement provides that the Trustee may only be removed and replaced by a vote of the holders of a majority of the outstanding Trust units at a special meeting of Trust unitholders called by either the Trustee or the holders of not less than 10% of the outstanding Trust units. 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 are not able to sue Whiting to enforce these rights.
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 had any contractual ability to influence or control the field operations of, and sale of oil and natural gas from, the underlying properties, including underlying properties where Whiting is the operator. Also, the Trust unitholders had no voting rights with respect to the operators of these properties and, therefore, had no managerial, contractual or other ability to influence the activities of the operators of these properties.
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 Trust has not requested a ruling from the IRS regarding the tax treatment of ownership of the Trust units. If the IRS were to determine (and be sustained in that determination) that the Trust is not a “grantor trust” for federal income tax purposes, or that the NPI is not properly treated as a production payment (and thus could fail to qualify as a debt instrument) for federal income tax purposes, the Trust unitholders may receive different and less advantageous tax treatment than they anticipated.
If the Trust were not treated as a grantor trust for federal income tax purposes, the Trust should be treated as a partnership for such purposes. Although the Trust would not become subject to federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the Trust unitholders, the Trust’s tax reporting requirements would be more complex and costly to implement and maintain, and its distributions to unitholders could be reduced as a result.
If the NPI were not treated as a debt instrument, any deductions allowed to an individual Trust unitholder in their recovery of basis in the NPI may be itemized deductions, the deductibility of which would be subject to limitations that may or may not apply depending upon the unitholder’s circumstances.
Neither Whiting nor the Trustee has requested a ruling from the IRS regarding these tax questions, and neither Whiting nor the Trust can assure that such a ruling would be granted if requested or that the IRS will not challenge this position on audit.
Thus, no assurance can be provided that the opinions and statements set forth in the discussion of U.S. federal income tax consequences would be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the Trust units and the prices at which Trust units trade. In addition, the costs of any contest with the IRS (whether or not such challenge is successful), principally legal, accounting and related fees, will result in a reduction in cash available for distribution to the Trust unitholders, and thus will be borne indirectly by the Trust unitholders.
Trust unitholders should be aware of the possible state tax implications of owning Trust units, and should consult their own tax advisors for advice regarding the state as well as federal tax implications of owning Trust units.
The Trust allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record ownership of the Trust units on the quarterly record date, instead of on the basis of the date a particular Trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the Trust unitholders.
The Trust generally allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record ownership of the Trust units on the quarterly record date, instead of on the basis of the date a particular Trust unit is transferred. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the Trust should be determined and allocated on a daily, prorated or other basis, which could require adjustments to the tax returns of the Trust unitholders affected by the issue and result in an increase in the administrative expense of the Trust in subsequent periods.
The tax treatment of an investment in Trust units could be affected by future legislative, judicial or administrative changes and differing opinions, possibly on a retroactive basis.
The U.S. federal income tax treatment of an investment in the Trust may be modified by administrative or legislative changes, or by judicial interpretation, at any time, possibly on a retroactive basis.
Trust unitholders will be required to pay taxes on their share of the Trust’s income even if they do not receive any cash distributions from the Trust.
For income tax purposes, Trust unitholders are treated as if they own the Trust’s taxable asset (which for tax purposes, is a loan receivable owed to the Trust from Whiting) and they receive the Trust’s income and are directly taxable thereon as if no trust were in existence. The Trust unitholders generally do not receive cash distributions from the Trust equal to their share of the Trust’s taxable income or even equal to the actual tax liability that results from that income. Because the Trust typically generates taxable income that is different in amount than the cash the Trust distributes, the Trust unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of the Trust’s taxable income even if they receive no cash distributions from the Trust.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
Description of the Underlying Properties
The underlying properties consisted 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 were located primarily in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions of the United States. The NPI terminated effective January 28, 2015, and the underlying properties reverted back to Whiting effective on such date. At the date of this Annual Report on Form 10-K, the Trust had no assets other than any cash held for current and future expenses and the terminated NPI.
Reserves
As of January 28, 2015, the NPI had terminated and Trust had no oil and gas reserves. As of December 31, 2014, however, the Trust still had 76 MBOE of proved oil and gas reserve attributable to it, and all of the Trust’s reserves were located 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, 2014 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, 2014) attributable to the Trust based on the term of its NPI (dollars in thousands):
(1) Oil and gas reserve quantities have been determined based upon NYMEX oil and gas prices of $94.99 per Bbl and $4.35 per MMBtu, respectively, which are calculated using an average of the first-day-of-the-month price for each month within the 12 months ended December 31, 2014, pursuant to current SEC and FASB guidelines. The average NYMEX oil and gas prices for the month of January 2015 were much lower than 12 month average prices as of December 31, 2014 in that crude oil was priced at $56.62 per Bbl and natural gas was $3.19 per MMBtu, respectively.
(2) Standardized measure of discounted future net cash flows as of December 31, 2014. 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.
(3) The Trust’s estimated proved reserves as of December 31, 2014 on a 90% basis were 76 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. The NPI terminated effective January 28, 2015.
(4) Oil includes natural gas liquids.
The above table does not include any proved undeveloped reserve quantities as of December 31, 2014 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, 2014. 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, 2012 to December 31, 2014, 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 2014, revisions to previous estimates decreased proved reserves by a net amount of 30 MBOE. Included in these revisions were 44 MBbl of downward adjustments to crude oil reserves, primarily due to lower oil prices of $79.30 per Bbl in reserve estimates at December 31, 2014, as compared to $84.40 per Bbl at December 31, 2013. This downward revision in crude oil reserves was partially offset by 14 MBOE (87 MMcf) of upward adjustments to natural gas reserves, primarily due to higher gas prices of $4.48 per Mcf in reserve estimates at December 31, 2014, as compared to gas prices of $3.72 per Mcf at December 31, 2013.
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 their own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Whiting’s current ownership in mineral interests and well production data are also subject to the aforementioned internal controls over financial reporting, and they are incorporated in the reserve database as well and verified to ensure their accuracy and completeness. Once the reserve database has been entirely updated with current information, and all relevant technical support material has been assembled, the Trust’s independent engineering firm Cawley, Gillespie & Associates, Inc. (“CG&A”) meets with Whiting’s technical personnel in Whiting’s Denver 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, 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 30 years of experience, the majority of which has involved reservoir engineering and reserve estimation, and he holds a Bachelor’s degree in petroleum engineering from the Colorado School of Mines. He is also a member of the Society of Petroleum Engineers.
Producing Acreage and Well Counts
The NPI terminated effective January 28, 2015, and therefore the Trust did not own any wells or acreage from and after such date.
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. Sales volumes for natural gas liquids are included with oil sales since they were not material.
(1) Oil includes natural gas liquids.
(2) Magnolia field was the only field that contained 15% or more of the total proved reserve volumes at December 31, 2014.
(3) Production costs reported above exclude from lease operating expenses ad valorem taxes of $0.8 million ($0.73/BOE), $0.9 million ($0.82/BOE) and $1.1 million ($0.94/BOE) for the years ended December 31, 2014, 2013 and 2012, respectively.
Producing wells that the NPI had a conveyed interest in are part of 14 enhanced oil recovery waterflood projects, and aggregate production from such enhanced oil recovery fields averaged 636 BOE/d during 2014 or 21% of 2014 daily production from the underlying properties. For these areas, Whiting needs to use enhanced recovery techniques in order to maintain oil and gas production from these fields.
Delivery Commitments
The NPI terminated effective January 28, 2015. The Trust has not committed to deliver fixed quantities of oil or gas in the future under any contracts or agreements.
Item 3.
Item 3. Legal Proceedings
Currently, there are not any legal proceedings pending to which the Trust is a party or of which any of its property is the subject.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
The Trust units commenced trading on the New York Stock Exchange on April 30, 2008 under the symbol “WHX” and were delisted from the New York Stock Exchange before market open on February 17, 2015. The Trust units transitioned to OTC Pink, operated by OTC Markets Group, effective with the opening of trading on February 17, 2015 under the symbol “WHXT”. 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 2014 and 2013 were as follows:
At December 31, 2014, 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. The table below presents the net cash proceeds for each quarter of 2014 and 2013 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 2, 2015, a distribution of $0.283085 per Trust unit was paid to Trust unitholders owning Trust units as of February 19, 2014. This aggregate distribution to all Trust unitholders consisted of net cash proceeds of $4.3 million paid by Whiting to the Trust, less a provision of $300,000 for estimated Trust expenses and $29,098 for Montana state income tax withholdings. In addition, there will be no payment made to unitholders for the final distribution period due to the net profits interest generating a $133,718 net loss from January 1, 2015 through the net profits interest termination date of January 28, 2015.
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 2014.
Item 6.
Item 6. Selected Financial Data
The following table sets forth selected data for the Trust for the years ended December 31, 2014, 2013 and 2012 and as of December 31, 2014, 2013 and 2012 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 include expectations or forecasts of future events. Please refer to “Forward-Looking Statements” which follows the Table of Contents of this Form 10-K for an explanation of these types of statements.
Trust Termination and Overview
The Trust does not conduct any operations or activities, and is currently in the process of winding up and terminating, as required by the Trust agreement. The Trust’s purpose is, in general, to hold the NPI, to distribute to unitholders cash that the Trust receives pursuant to the NPI, and to perform certain administrative functions with respect to the NPI and the Trust units. The NPI terminated effective January 28, 2015 as a result of 9.11 MMBOE (8.20 MMBOE at the 90% NPI) having been produced and sold from the underlying properties. As previously disclosed in the press release issued by the Trust on March 10, 2015, there will be no payment made to unitholders for the final Trust distribution period due to the net profits interest generating a $133,718 net loss from January 1, 2015 through the net profits interest termination date of January 28, 2015.
Given the time lag between when production is sold and the related revenues are received and expenses relating thereto are paid, on or about August 31, 2015, the Trust may make a true-up distribution if, after the receipt of revenues and payment of expenses, there are any positive net proceeds to distribute after recovery of the $133,718 net loss generated during the final distribution period. Unitholders of record on March 19, 2015 will be entitled to such distribution, if any. If the true-up calculation results in an increased net loss, the Trust will not be responsible for repayment of any portion of the net loss. As of March 19, 2015, 99.9% of the Trust’s total 13,863,889 units outstanding were held by Cede & Co., which is the DTC’s nominee, and Whiting as the official unitholders of record. Therefore, the March 19, 2015 record date, as it relates to any potential true-up distribution, is only applicable to unitholders of record such as Cede & Co. and Whiting, and the ex-date actually determines which street name holders will be eligible to receive a true-up distribution, if any such distribution is made by the Trust. It is likely that there may not be any true-up distribution or, if there is one, it is not likely to be significant. After any true-up distribution or determination that no such payment will be made, the Trust will soon thereafter wind up its affairs and terminate. The Trust units are expected to be canceled during the third quarter of 2015, and except for the slight possibility of a minor true-up distribution as discussed above, the Trust will not make any future distributions whatsoever. Additionally, as previously announced, the stock transfer books for the Trust were closed at the close of business on March 19, 2015.
Oil and gas prices historically have been volatile and may fluctuate widely in the future. The table below highlights these price trends by listing quarterly average NYMEX crude oil and natural gas prices for the periods indicated through December 31, 2014. The 2014 NPI distributions were mainly affected, however, by October 2013 through September 2014 oil prices and by September 2013 through August 2014 natural gas prices.
Oil prices have fallen significantly since reaching highs of over $105.00 per Bbl in June 2014, dropping below $45.00 per Bbl in January 2015. Natural gas prices have also declined from over $4.80 per Mcf in April 2014 to below $2.60 per Mcf in February 2015. In addition, forecasted prices for both oil and gas for 2015 have also declined. Lower oil and gas prices on production from the underlying properties could cause a reduction in the amount of net proceeds to which the Trust is entitled. All costless collar hedge contracts Whiting entered into, and in turn conveyed to the Trust, terminated as of December 31, 2012 (which hedging effects impacted the February 2013 distribution to unitholders and ceased thereafter) and no additional hedges are allowed to be
placed on the Trust assets. Consequently, for production applicable to quarterly payment periods after the February 2013 distribution, there has been and will be no cash settlement gains or losses on commodity derivatives, and the Trust has had and will have increased exposure to oil and natural gas price volatility since the February 2013 distribution.
The Trust units ceased trading on NYSE effective before market open on February 17, 2015. The NYSE informed the Trust that the Trust was not in compliance with the NYSE’s continued listing standards, which require that the average closing price of the Trust units cannot be less than $1.00 per share over a period of 30 consecutive trading days. The Trust units transitioned to OTC Pink, operated by OTC Markets Group, effective with the opening of trading on February 17, 2015. The Trust can provide no assurance that any trading market for the Trust units will exist on OTC Pink or that current trading levels will be sustained or not diminish.
Establishment of Reserves. The Trust agreement authorizes the Trustee to establish a cash reserve for the payment of any liability that is contingent or uncertain in amount or that is not otherwise currently due and payable. In preparation for the termination of the Trust, the Trustee established a cash reserve of $100,000 for the payment of Trust termination-related expenses, that are estimated to be incurred or paid after the final distribution to unitholders. The withholdings to establish this cash reserve were included in the November 2014 distribution within the provision for estimated Trust expenses, which was a reduction of net proceeds. This reserve may be funded from time to time by additional withholdings the Trustee, in its discretion, deems appropriate for contingent liabilities in accordance with Section 3808 of the Delaware Statutory Trust Act. All such reserves reduce distributions to unitholders. In addition, any true-up distribution to unitholders will be subject to the payment of all expenses and liabilities of the Trust.
Impairment of Net Profits Interest. As of December 31, 2014, the Trust’s investment in the NPI with a carrying value of $5.3 million was written down to its fair value of $3.9 million, resulting in a $1.4 million impairment charged directly to Trust corpus. The write-down of the investment in NPI is related to the decrease in the forward price curve for crude oil and natural gas as of December 31, 2014, and the $3.9 million of investment in net profits interest is solely related to the February 2015 distribution amount.
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 following is a summary of income from net profits interest and distributable income received by the Trust for the years ended December 31, 2014, 2013 and 2012, consisting of the February, May, August and November distributions for each respective year (dollars in thousands, except per Bbl, per Mcf and per BOE amounts):
(a) Oil includes natural gas liquids.
(b) Oil and gas sales volumes and related revenues for the year ended December 31, 2014 (consisting of Whiting’s February 2014, May 2014, August 2014 and November 2014 distributions to the Trust) generally represent crude oil production from October 2013 through September 2014 and natural gas production from September 2013 through August 2014.
(c) Oil and gas sales volumes and related revenues for the year ended December 31, 2013 (consisting of Whiting’s February 2013, May 2013, August 2013 and November 2013 distributions to the Trust) generally represent crude oil production from October 2012 through September 2013 and natural gas production from September 2012 through August 2013.
(d) Oil and gas sales volumes and related revenues for the year ended December 31, 2012 (consisting of Whiting’s February 2012, May 2012, August 2012 and November 2012 distributions to the Trust) generally represent crude oil production from October 2011 through September 2012 and natural gas production from September 2011 through August 2012.
(e) As discussed below, all hedges terminated as of December 31, 2012 and thereby cease to affect distributions after the February 2013 distribution.
Comparison of Results of the Trust for the Years Ended December 31, 2014 and 2013
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 $1.5 million or 2% in 2014 compared to 2013. Sales revenue is a function of average commodity prices realized and oil and gas volumes sold. The increase in revenue between periods was due to higher sales prices realized for crude oil and natural gas, as well as higher oil production volumes during 2014. These increases were partially offset, however, by lower natural gas production volumes between periods. The average sales price realized before the effects of hedging increased for oil by 1% and for gas by 20% during 2014 compared to 2013. Oil sales volumes increased 2 MBbls (or 0.3%), while gas sales volumes decreased 188 MMcf (or 7%) between periods. The oil volume increase was primarily related to i) six new wells that came online during the last twelve months and ii) differences in timing associated with revenues received from non-operated properties. These oil volume increases were partially offset by normal field production decline. The gas volume decrease was primarily related to normal field production decline, which was partially offset by new wells that came online during the last twelve months.
Lease Operating Expenses. LOE increased $0.4 million or 2% during 2014 compared to 2013, primarily due to a $0.7 million increase in the cost of oilfield goods and services, partially offset by $0.2 million in lower plug and abandonment charges between periods. The increase in overall LOE coupled with the decrease in overall production volumes between periods resulted in an increase in LOE on a per BOE basis of 4%, from $25.96 in 2013 to $27.05 in 2014.
Production Taxes. Production taxes are typically calculated as a percentage of oil and gas revenues before the effects of hedging, and production taxes as a percent of revenues remained relatively consistent at 7.0% and 6.9% during 2014 and 2013, respectively. Overall production taxes during 2014 increased, however, by $0.2 million (or 3%) compared to 2013, primarily due to higher oil and gas sales revenue between periods.
Cash Settlements on Commodity Derivatives. In connection with Whiting’s conveyance of the net profits interest to the Trust, Whiting entered into certain costless collar hedge contracts in order to reduce the Trust’s exposure to commodity price volatility. If market prices were lower than a collar’s price floor when the cash settlement amount was calculated, Whiting received cash proceeds from the contract counterparty, which proceeds were in turn included in NPI distributions to the Trust. Conversely, if market prices were higher than a collar’s price ceiling when the cash settlement amount was calculated, Whiting was required to pay the contract counterparty, which payments were included as reductions of net proceeds in NPI distributions to the Trust.
All such conveyed hedges terminated as of December 31, 2012, and all hedge related pricing impacts ceased after the February 2013 distribution. Thus, there were no hedges in effect or related cash settlements during 2014. Hedge cash settlements in 2013, however, resulted in a gain of $1.4 million for the year ended December 31, 2013, which had the effect of increasing the average realized price of natural gas by $0.53 per Mcf for that period. As a result, the total net price of natural gas of $4.02 per Mcf that the Trust received for the year ended December 31, 2013, included a premium of 13% related to the effects of hedging.
Provision for Estimated Trust Expenses. The provision for estimated Trust expenses during 2014 increased 60% as compared to 2013 primarily due to an increase in cash reserves withheld of $0.5 million between periods, for both current as well as termination-related expenses of the Trust.
Distributable Income. For the year ended December 31, 2014, the Trust’s distributable income was $29.1 million and was based on income from net profits interest of $30.5 million, reduced by Trust general and administrative expenses of $0.9 million and Montana state income tax withholdings of $0.2 million, and adjusted for changes in Trust cash reserves. This compares to distributable income of $29.9 million during 2013, which was based on income from net profits interest of $30.9 million, reduced by Trust general and administrative expenses of $0.9 million and Montana state income tax withholdings of $0.2 million, and adjusted for changes in Trust cash reserves.
Comparison of Results of the Trust for the Years Ended December 31, 2013 and 2012
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 $3.3 million or 5% in 2013 compared to 2012. Sales revenue is a function of average commodity prices realized and oil and gas volumes sold. The decrease in revenue between periods was due to lower oil and natural gas production volumes in 2013, partially offset by higher sales prices realized for crude oil and natural gas during 2013. Oil sales volumes decreased 7% or 55 MBbls, and gas sales volumes decreased 8% or 225 MMcf during 2013 as compared to 2012. Both of these volume decreases were primarily related to i) normal field production decline and ii) differences in timing associated with revenues distributed and received from non-operated properties. The oil volume decline was partially offset by production increases from five new oil wells that came online during 2013. The average price for gas before the effects of hedging increased 10% between periods, and the average price for oil before the effects of hedging increased 2% between periods.
Lease Operating Expenses. LOE remained consistent at $29.5 million for both 2013 and 2012, primarily due to increases in plug and abandonment charges of $0.6 million and labor costs of $0.5 million, offset by a decrease in the cost of oilfield goods and services of $1.1 million in 2013 compared to 2012. The decrease in overall production volumes between periods resulted in an increase in LOE on a per BOE basis of 8%, however, from $23.99 in 2012 to $25.96 in 2013.
Production Taxes. Production taxes are typically calculated as a percentage of oil and gas revenues before the effects of hedging, and production taxes as a percent of revenues remained relatively consistent at 6.9% and 6.8% during 2013 and 2012, respectively. Overall production taxes during 2013 decreased, however, by $0.2 million (or 4%) compared to 2012, primarily due to lower oil and gas sales revenue between periods.
Cash Settlements on Commodity Derivatives. In connection with Whiting’s conveyance of the net profits interest to the Trust, Whiting entered into certain costless collar hedge contracts in order to reduce the Trust’s exposure to commodity price volatility. If market prices were lower than a collar’s price floor when the cash settlement amount was calculated, Whiting received cash proceeds from the contract counterparty. Conversely, if market prices were higher than a collar’s price ceiling when the cash settlement amount was calculated, Whiting was required to pay the contract counterparty.
Cash settlements relating to these hedges resulted in a gain of $1.4 million for the year ended December 31, 2013, which had the effect of increasing the average realized price of natural gas by $0.53 per Mcf for that period, and cash settlements relating to these hedges resulted in a gain of $5.9 million for the year ended December 31, 2012, which had the effect of increasing the average realized price of natural gas by $2.12 per Mcf for that period. As a result, the total net price of natural gas of $4.02 per Mcf and $5.28 per Mcf that the Trust received for 2013 and 2012, respectively, included premiums of 13% and 40%, respectively, related to
the effects of hedging for those same periods. All hedge related pricing impacts ceased after the February 2013 distribution, which had the effect of increasing the Trust’s exposure to oil and natural gas price volatility beginning with the May 2013 distribution through the January 28, 2015 NPI termination date.
Provision for Estimated Trust Expenses. The provision for estimated Trust expenses during 2013 decreased $0.2 million as compared to 2012 primarily due to a decline in cash reserves withheld for current Trust expenses of $0.2 million between periods.
Distributable Income. For the year ended December 31, 2013, the Trust’s distributable income was $29.9 million and was based on income from net profits interest of $30.9 million, reduced by Trust general and administrative expenses of $0.9 million and Montana state income tax withholdings of $0.2 million, and adjusted for changes in Trust cash reserves. This compares to distributable income of $36.7 million during 2012, which was based on income from net profits interest of $37.9 million, reduced by Trust general and administrative expenses of $0.8 million and Montana state income tax withholdings of $0.3 million, and adjusted for changes in Trust cash reserves.
Liquidity and Capital Resources
The Trust has no source of liquidity or capital resources other than cash flows from the NPI, which terminated effective January 28, 2015. Other than Trust administrative expenses, including any reserves established by the Trustee for future liabilities, the Trust’s only use of cash is for distributions to Trust unitholders. Administrative expenses include payments to the Trustee and the Delaware Trustee, a quarterly fee paid to Whiting pursuant to an administrative services agreement, and expenses in connection with the discharge of the Trustee’s duties, including third party engineering, audit, accounting and legal fees. Each quarter, the Trustee determines the amount of funds available for distribution to unitholders. Available funds are the excess cash, if any, received by the Trust from the NPI and other sources (such as interest earned on any amounts reserved by the Trustee) that quarter, over the Trust’s expenses for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities.
In preparation for the termination of the Trust, the Trustee established a cash reserve of $100,000 for the payment of Trust termination-related expenses that are estimated to be incurred or paid after the final distribution to unitholders. The withholdings to establish this cash reserve were included in the November 2014 distribution within the provision for estimated Trust expenses, which is a reduction of net proceeds. This reserve may be funded by additional withholdings to the extent the Trustee, in its discretion, deems such withholdings appropriate for contingent liabilities in accordance with Section 3808 of the Delaware Statutory Trust Act. All such reserves reduce distributions to unitholders. Any true-up distribution to be made by August 31, 2015, if necessary, will be subject to the payment of all expenses and liabilities of the Trust.
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. In February 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 event that Whiting should fail to lend funds to the Trust if requested to do so by the Trustee. This letter of credit will not be used to fund NPI distributions to unitholders, and Whiting has no obligation to lend funds to the Trust. If the Trustee were to draw on the letter of credit or borrow funds from Whiting or otherwise, no further distributions would be made to unitholders until all such amounts have been repaid by the Trust.
Income to the Trust from the NPI is based on the calculation and definitions of “gross proceeds” and “net proceeds” contained in the conveyance agreement, which is filed as an exhibit to this report, and reference is hereby made to such conveyance agreement 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 $5.2 million on the underlying properties during 2014, compared to $7.1 million in 2013 and $6.8 million in 2012. Such expenditures were not deducted from gross proceeds or Trust distributions.
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.
Contractual Obligations
The following table summarizes the Trust’s obligations and commitments as of December 31, 2014 to make future payments during the specified time periods:
(a) Pursuant to the terms of the Trust agreement, the Trust is obligated to pay the Trustee an annual administrative fee of $160,000, paid in four quarterly installments of $40,000.
(b) Pursuant to the terms of the administrative services agreement with Whiting, the Trust is obligated throughout the term of the net profits interest to pay Whiting an administrative services fee of $50,000 per quarter for accounting, engineering, legal and other professional services performed by Whiting on behalf of the Trust. The administrative services agreement expired upon the termination of the NPI effective January 28, 2015.
(c) The 2015 period represents estimated obligations through the Trust termination date. Actual amounts paid may differ from these estimates.
New Accounting Pronouncements
There were no accounting pronouncements issued during the year ended December 31, 2014 applicable to the Trust or its financial statements.
Critical Accounting Policies and Estimates
The financial statements of the Trust are significantly affected by its basis of accounting and estimates related to its oil and gas properties and proved reserves, as summarized below.
Basis of Accounting. The Trust’s financial statements are prepared on a modified cash basis, which is a comprehensive basis of accounting other than GAAP. This method of accounting is consistent with reporting of taxable income to the Trust unitholders. The most significant differences between the Trust’s financial statements and those prepared in accordance with GAAP are:
a) Income from net profits interest is recognized when NPI distributions are received by the Trust rather than accrued in the month of production that they are earned;
b) Distributions to Trust unitholders are recorded when paid by the Trust rather than accrued when owed;
c) Trust general and administrative expenses (which include the Trustee’s fees as well as administrative, accounting, engineering, legal and other professional fees) are recorded when paid by the Trust rather than when incurred; and
d) Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under GAAP.
While these statements differ from financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues and distributions is considered to be the most meaningful for the Trust and its results because quarterly distributions to the Trust unitholders are based on net cash receipts. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by FASB ASC Topic 932, Extractive Activities - Oil and Gas: Financial Statements of Royalty Trusts. For additional information regarding the Trust’s basis of accounting, see Note 2 to the Financial Statements included in this Annual Report on Form 10-K.
All amounts included in the Trust’s financial statements are based on cash amounts received or disbursed, or on the carrying value of the net profits interests, which was derived from the historical cost of the interests at the date of their transfer from Whiting less accumulated amortization and impairment charges to date.
Oil and Gas Reserves. The proved oil and gas reserves for the underlying properties are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices and production costs, may justify revision of such estimates. Accordingly, oil and gas quantities ultimately recovered and the timing of production may be substantially different from estimates, and we are unable to predict changes in reserve quantity estimates as such quantities are dependent on future economic and operational conditions.
The standardized measure of discounted future net cash flows is prepared using assumptions made pursuant to FASB and SEC guidelines. Such assumptions include using average fiscal-year oil and gas prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month reporting period) and year-end costs for estimated future production expenditures. Discounted future net cash flows are calculated using a 10% discount rate. Changes in any of these assumptions could have a significant impact on the standardized measure. The standardized measure does not necessarily result in an estimate of the current fair market value of proved reserves.
Amortization of Net Profits Interest. We amortize the investment in net profits interest using the units-of-production method. Our rate of recording amortization is dependent upon our estimates of total proved reserves, which incorporates various assumptions and future projections. If the estimates of total proved reserves decline significantly, the rate at which we record amortization expense would increase, reducing Trust corpus.
Impairment of Investment in Net Profits Interest. We review the value of our investment in net profits interest whenever the Trustee judges that events and circumstances indicate that the recorded carrying value of the investment in net profits interest may not be recoverable. Potential impairments of the investment in net profits interest are determined by comparing future net undiscounted cash flows to the net book value at the end of each period. If the net capitalized cost exceeds undiscounted future cash flows, the cost of the investment in net profits interest is written down to “fair value,” which is determined using net discounted future cash flows from the net profits interest. Different pricing assumptions or discount rates could result in a different calculated impairment.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Hedge Contracts
The primary asset and source of income to the Trust is the term NPI, which terminated effective January 28, 2015 but which generally entitled the Trust to receive 90% of the net proceeds from oil and gas production from the underlying properties. Consequently, the Trust was exposed to market risk from fluctuations in oil and gas prices.
The revenues derived from the underlying properties depended substantially on prevailing crude oil, natural gas and natural gas liquid prices. As a result, commodity prices affected the amount of cash flow available for distribution to the Trust unitholders. Whiting sold the oil, natural gas and natural gas liquid production from the underlying properties under floating market price contracts each month. Whiting entered into certain hedge contracts through December 31, 2012 (which had effects extending through the February 2013 distribution to unitholders) to manage the exposure to crude oil and natural gas price volatility associated with revenues generated from the underlying properties, and to achieve more predictable cash flows. However, all hedging contracts terminated as of December 31, 2012, which effects in turn terminated as of the February 2013 distribution. No additional hedges are allowed to be placed on Trust assets, nor can the Trust enter into derivative contracts for speculative or trading purposes.
Item 8.
Item 8. Financial Statements and Supplementary Data
Index to Whiting USA Trust I Financial Statements
(Modified Cash Basis)
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, 2014 and 2013, and the related statements of distributable income and changes in trust corpus - modified cash basis for the years ended December 31, 2014, 2013, and 2012. 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 1 to the financial statements, the NPI terminated effective January 28, 2015 as a result of 9.11 MMBOE (which amount is equivalent to 8.20 MMBOE attributable to the NPI) having been produced and sold from the underlying properties. 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, 2014 and 2013, and its distributable income and changes in trust corpus for the years ended December 31, 2014, 2013, and 2012, on the comprehensive basis of accounting described in Note 2 to the financial statements.
/s/ Deloitte & Touche LLP
Austin, Texas
March 20,
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 NPI for the benefit of the Trust unitholders pursuant to a conveyance to the Trust from Whiting Oil and Gas. The term NPI, which terminated effective January 28, 2015, was an interest in certain of Whiting Oil and Gas’ properties located in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions (the “underlying properties”). The terminated NPI is the only asset of the Trust, other than cash reserves held for Trust expenses. As of December 31, 2014, these oil and gas properties included interests in 3,061 gross (332.9 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 terminated effective January 28, 2015 as a result of 9.11 MMBOE (which amount is equivalent to 8.20 MMBOE attributable to the NPI) having been produced and sold from the underlying properties. As of December 31, 2014, on a cumulative accrual basis 8.11 MMBOE (99%) of the Trust’s total 8.20 MMBOE had been produced and sold and a cumulative 0.02 MMBOE had been sold in divestitures.
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 that the terms of the loan are similar to the terms it would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself, which may be a non-interest bearing account, and make other short-term investments with the funds distributable to the Trust. As of December 31, 2014 and 2013, the Trust had no outstanding borrowings.
Initial Issuance of Trust Units and Net Profits Interest Conveyance - In April 2008, the Trust issued 13,863,889 Trust units to Whiting in exchange for the conveyance of the term NPI, which is described above, from Whiting Oil and Gas. Immediately thereafter, Whiting completed an initial public offering of units of beneficial interest in the Trust, selling 11,677,500 Trust units to the public. Whiting retained, and has continued to retain, 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. 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) are recorded when paid;
d) Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under GAAP;
e) Amortization of the investment in net profits interest is calculated based on the units-of-production method. Such amortization is charged directly to Trust corpus and does not affect distributable income; and
f) The Trust evaluates impairment of the investment in net profits interest by comparing the undiscounted cash flows expected to be realized from the investment in net profits interest to the NPI carrying value. If the expected future undiscounted cash flows are less than the carrying value, the Trust recognizes an impairment loss for the difference between the carrying value and the estimated fair value of the investment in net profits interest. The fair value of the NPI is determined using the expected net discounted future cash flows from the underlying properties that are attributable to the net profits interest. The determination of whether the NPI is impaired requires a significant amount of judgment by the Trustee and is based on the best information available to the Trustee at the time of the evaluation.
While these statements differ from financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues and distributions is considered to be the most meaningful for the Trust’s activities and results because quarterly distributions to the Trust unitholders are based on net cash receipts. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by FASB ASC Topic 932, Extractive Activities - Oil and Gas: Financial Statements of Royalty Trusts.
Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with GAAP, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues are received or expenses are paid. Because the Trust’s financial statements are prepared on the modified cash basis as described above, however, most accounting pronouncements are not applicable to the Trust’s financial statements.
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 was derived principally sell their oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. The following table presents the percentages by purchaser that accounted for 10% or more of the underlying properties’ total oil and natural gas sales for the years ended December 31, 2014, 2013 and 2012:
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.
Recent Accounting Pronouncements - There were no accounting pronouncements issued during the year ended December 31, 2014 applicable to the Trust or its financial statements.
3. INVESTMENT IN NET PROFITS INTEREST
Net Profits Interest Conveyance - 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 of the investment in net profits interest as of December 31, 2014 and 2013,was zero and $93.2 million, respectively.
Impairment of Net Profits Interest - As of December 31, 2014, the investment in net profits interest with a carrying value of $5.3 million was written down to its fair value of $3.9 million, resulting in a $1.4 million impairment which is charged directly to Trust corpus and does not affect distributable income. The write-down of the investment in NPI is related to the decrease in the forward price curve for crude oil and natural gas on December 31, 2014, and the remaining $3.9 million investment in net profits interest is solely related to the February 2015 distribution amount. However, the fair value of the investment in net profits interest contains certain unobservable inputs including estimates of future oil and gas production attributable to the Trust; commodity prices based on sales contract terms or NYMEX forward price curves as of December 31, 2014 (adjusted for basis differentials); estimated operating and general and administrative expenses; estimated state income tax withholdings; and a risk-adjusted discount rate.
As of December 31, 2013, no such impairment of the investment in net profits interest had occurred.
4. INCOME FROM NET PROFITS INTEREST
The Trust received income from net profits interest as follows (dollars in thousands):
(a) Oil includes natural gas liquids.
(b) Oil and gas sales volumes and related revenues for the year ended December 31, 2014 (consisting of Whiting’s February 2014, May 2014, August 2014 and November 2014 distributions to the Trust) generally represent crude oil production from October 2013 through September 2014 and natural gas production from September 2013 through August 2014.
(c) Oil and gas sales volumes and related revenues for the year ended December 31, 2013 (consisting of Whiting’s February 2013, May 2013, August 2013 and November 2013 distributions to the Trust) generally represent crude oil production from October 2012 through September 2013 and natural gas production from September 2012 through August 2013.
(d) Oil and gas sales volumes and related revenues for the year ended December 31, 2012 (consisting of Whiting’s February 2012, May 2012, August 2012 and November 2012 NPI distributions to the Trust) generally represent crude oil production from October 2011 through September 2012 and natural gas production from September 2011 through August 2012.
(e) All hedges terminated as of December 31, 2012 and thereby cease to affect the distributions after the February 2013 distribution.
5. INCOME TAXES
The Trust is a grantor trust and therefore is not subject to federal income taxes. Accordingly, no recognition has been given to federal income taxes in the Trust’s financial statements or in the Trust’s standardized measure of discounted future net cash flows. The Trust unitholders are treated as the owners of Trust income and corpus, and the entire taxable income of the Trust is reported by the Trust unitholders on their respective tax returns.
For Montana state income tax purposes, Whiting must withhold from its NPI payments to the Trust, an amount equal to 6% of the net amount payable to the Trust from the sale of oil and gas in Montana. Whiting withheld $0.2 million, $0.2 million and $0.3 million related to Montana state income taxes for the years ended December 31, 2014, 2013 and 2012, respectively. For Alabama, Arkansas, Colorado, Kansas, Louisiana, Michigan, Mississippi, New Mexico, North Dakota, Oklahoma and Utah, neither the Trust nor Whiting is withholding the income tax due such states on distributions made to an individual resident or nonresident Trust unitholder, as long as the Trust is taxed as a grantor trust under the Internal Revenue Code.
6. DISTRIBUTION TO UNITHOLDERS
Actual cash distributions to the Trust unitholders depend on the volumes of and prices received for oil, natural gas and natural gas liquids produced from the underlying properties, among other factors. Quarterly cash distributions during the term of the Trust are made by the Trustee no later than 60 days following the end of each quarter (or the next succeeding business day) to the Trust unitholders of record on the 50th day following the end of each quarter. Such amounts equal the excess, if any, of the cash received by the Trust during the quarter, over the expenses of the Trust paid during such quarter, subject to any adjustments for changes made by the Trustee during such quarter in any cash reserves established for future expenses of the Trust.
7. RELATED PARTY TRANSACTIONS
Capital Expenditures - During the years ended December 31, 2014, 2013 and 2012, Whiting incurred $5.2 million, $7.1 million and $6.8 million, respectively, of capital expenditures on the underlying properties. These capital expenditures are the costs net to Whiting’s interest in the wells and which are related to the drilling and completing of oil and gas wells, capital workovers, facility upgrades and well recompletions that are performed to secure production from new horizons. Pursuant to the terms of the conveyance agreement, such expenditures were not deducted from gross proceeds or the Trust distributions.
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, with respect to those underlying properties for which Whiting is the operator but where there is no operating agreement in place, Whiting deducts from the gross proceeds an overhead fee calculated in the same manner that Whiting allocates overhead to other similarly owned properties, which is customary practice in the oil and gas industry. Operating overhead activities include various engineering, legal and administrative functions. The fee is adjusted annually pursuant to COPAS guidelines and will increase or decrease each year based on changes in the year-end index of average weekly earnings of crude petroleum and natural gas workers. The following table presents the Trust’s portion of these overhead charges for the distributions made during the years ended December 31, 2014, 2013 and 2012 (dollars in thousands, except monthly amounts per well):
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 years ended December 31, 2014, 2013 and 2012 each include $200,000 for quarterly administrative fees paid to Whiting.
Trustee Administrative Fee - Under the terms of the Trust agreement, the Trust pays an annual administrative fee to the Trustee of $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, 2014, 2013 and 2012 each include $160,000 for quarterly administrative fees paid to the Trustee.
Letter of Credit - In February 2011, Whiting established a $1.0 million letter of credit for the Trustee in order to provide it with a mechanism to pay the operating expenses of the Trust, in the event that Whiting should fail to lend funds to the Trust if requested to do so by the Trustee. This letter of credit will not be used to fund NPI distributions to unitholders, and Whiting has no obligation to lend funds to the Trust. If the Trustee were to draw on the letter of credit or borrow funds from Whiting or otherwise, no further distributions would be made to unitholders until all such amounts have been repaid by the Trust.
8. SUBSEQUENT EVENTS
Net Profits Interest Termination - On January 28, 2015, the net profits interest terminated as a result of 9.11 MMBOE (which amount is equivalent to 8.20 MMBOE attributable to the net profits interest) having been produced and sold from the underlying properties. Unitholders of record on February 19, 2014 received a distribution of $0.283085 per Trust unit on March 2, 2015. The distribution consisted of net cash proceeds of $4.3 million paid by Whiting to the Trust, less a provision of $300,000 for estimated Trust expenses and $29,098 for Montana state income tax withholdings.
As previously disclosed in the press release issued by the Trust on March 10, 2015, there will be no payment made to unitholders for the final Trust distribution period due to the net profits interest generating a $133,718 net loss from January 1, 2015 through the net profits interest termination date of January 28, 2015. Given the time lag between when production is sold and the related revenues are received and expenses relating thereto are paid, on or about August 31, 2015, the Trust may make a distribution if, after the receipt of revenues and payment of expenses, there are any positive net proceeds to distribute after recovery of the $133,718 net loss generated during the final distribution period (the “true-up distribution”). Unitholders of record on March 19, 2015, will be entitled to such distribution, if any. If the true-up calculation results in an increased net loss, the Trust will not be responsible for repayment of any portion of the net loss. As of March 19, 2015, 99.9% of the Trust’s total 13,863,889 units outstanding were held by Cede & Co., which is the DTC’s nominee, and Whiting as the official unitholders of record. Therefore, the March 19, 2015 record date, as it relates to any potential true-up distribution, is only applicable to unitholders of record such as Cede & Co. and Whiting, and the ex-date actually determines which street name holders will be eligible to receive a true-up distribution, if any such distribution is made by the Trust. It is likely that there may not be any true-up distribution or, if there is one, it is not likely to be significant. After any true-up distribution or determination that no such payment will be made, the Trust will soon thereafter wind up its affairs and terminate. The Trust units are expected to be canceled during the third quarter of 2015, and except for the slight possibility of a minor true-up distribution as discussed above, the Trust will not make any future distributions whatsoever. Additionally, as previously announced, the stock transfer books for the Trust were closed at the close of business on March 19, 2015.
Delisting of the Trust - The Trust was informed by the New York Stock Exchange (the “NYSE”) on February 13, 2015, that the Trust was not in compliance with the NYSE’s continued listing standards, which require that the average closing price of the Trust units cannot be less than $1.00 per share over a period of 30 consecutive trading days. Under the NYSE delisting procedures, the Trust has the right to appeal such decision, but the Trust does not intend to do so. As a result, the Trust units ceased trading on the NYSE effective before market open on February 17, 2015. The Trust units transitioned to the OTC Pink, operated by OTC Markets Group, effective with the opening of trading on February 17, 2015. The new trading symbol for the Trust units on OTC Pink is “WHXT”.
9. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
Estimates of proved reserves attributable to the Trust and the related valuations were based on reports prepared by the Trust’s independent petroleum engineers Cawley, Gillespie & Associates, Inc. Proved reserve estimates included herein conform to the definitions prescribed by the FASB and SEC. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.
As of December 31, 2014, 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.
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, 2012, 2013 and 2014:
(1) Reserves related to the underlying properties on a 100% full economic life basis as of January 1, 2012 and as of December 31, 2012, 2013 and 2014 were 13.0 MMBOE, 10.8 MMBOE, 9.2 MMBOE and 9.1 MMBOE, respectively. The oil and gas reserve quantities presented in the tables above are on a 90% NPI Trust life basis.
(2) These tables do not include quantities of proved undeveloped reserves as of January 1, 2012 or as of December 31, 2012, 2013 and 2014 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.
Notable changes in proved reserves for the year ended December 31, 2014 included:
•
Revisions to previous estimates. In 2014, revisions to previous estimates decreased proved reserves by a net amount of 30 MBOE. Included in these revisions were 44 MBbl of downward adjustments to crude oil reserves, primarily due to lower oil prices of $79.30 per Bbl in reserve estimates at December 31, 2014, as compared to $84.40 per Bbl at December 31, 2013. This downward revision in crude oil reserves was partially offset by 14 MBOE (87 MMcf) of upward adjustments to natural gas reserves, primarily due to higher gas prices of $4.48 per Mcf in reserve estimates at December 31, 2014, as compared to gas prices of $3.72 per Mcf at December 31, 2013.
Notable changes in proved reserves for the year ended December 31, 2013 included:
•
Revisions to previous estimates. In 2013, revisions to previous estimates decreased proved reserves by a net amount of 36 MBOE. Included in these revisions were 118 MBbl of downward adjustments to crude oil reserves, primarily due to reservoir analysis and well performance. This downward revision in crude oil reserves was partially offset by 82 MBOE (494 MMcf) of upward adjustments to natural gas reserves, primarily due to higher gas prices of $3.72 per Mcf in reserve estimates at December 31, 2013, as compared to gas prices of $3.07 per Mcf at December 31, 2012.
Notable changes in proved reserves for the year ended December 31, 2012 included:
•
Revisions to previous estimates. In 2012, revisions to previous estimates decreased proved reserves by a net amount of 17 MBOE. Included in these revisions were 36 MBOE (214 MMcf) of downward adjustments to natural gas, primarily due to lower gas prices of $3.07 per Mcf in reserve estimates at December 31, 2012, as compared to gas prices of $4.10 per Mcf at December 31, 2011. This downward revision in natural gas reserves was partially offset by 19 MBbl of upward adjustments to crude oil reserves primarily due to increased estimates of future production resulting from workovers and well performance.
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 932, Extractive Activities - Oil and Gas. Future cash inflows as of December 31, 2014, 2013 and 2012 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, 2014, 2013 and 2012, respectively) 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.
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, 2014, 2013 and 2012 as follows:
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 forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by Whiting to The Bank of New York Mellon Trust Company, N.A., as Trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, the Trustee carried out an evaluation of the 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 the “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report on Form 10-K, for a description of the Trust’s 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, 2014, 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 registrant’s assets that could have a material effect on the financial statements.
The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities and Exchange Act of 1934, as amended. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with the modified cash basis of accounting. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control-Integrated Framework (2013), the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2014.
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 20, 2015
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 2014.
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, 2014, 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
In February 2011, Whiting established a $1.0 million letter of credit for the Trustee in order to provide it with a mechanism to pay the operating expenses of the Trust, in the event that Whiting should fail to lend funds the Trust if requested to do so by the Trustee. This letter of credit will not be used to fund NPI distributions to unitholders, and Whiting has no obligation to lend funds to the Trust. If the Trustee were to draw on the letter of credit or borrow funds from Whiting or otherwise, no further distributions would be made to unitholders until all such amounts have been repaid by the Trust.
Capital Expenditures
During the year ended December 31, 2014, Whiting incurred capital expenditures of $5.2 million on the underlying properties. These capital expenditures are the costs net to Whiting’s interest in the wells and which are related to the drilling and completing of oil and gas wells, capital workovers, facility upgrades and well recompletions that are performed to secure production from new horizons. Pursuant to the conveyance agreement, such expenditures were not deducted from gross proceeds or the distributions in 2014.
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, 2014, the Trust’s portion of the monthly charge totaled $1.9 million and averaged $534 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, 2014 include $200,000 for quarterly administrative fees paid to Whiting.
The administrative services agreement terminated on January 28, 2015, the net profits interest termination date.
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, 2014 include $160,000 for quarterly administrative fees paid to the Trustee.
The Trust agreement will expire upon termination of the Trust, which is expected to occur during the third quarter of 2015.
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. Neither Whiting nor any holder has requested to register any units pursuant to the registration rights agreement.
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 (“Deloitte”) as the independent registered public accounting firm to audit the Trust’s financial statements for the fiscal year ended December 31, 2014. During fiscal 2014 and 2013, 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, 2014 and 2013 by Deloitte (dollars in thousands):
(1) Fees for audit services in 2014 and 2013 consisted of the audit of the Trust’s annual financial statements and reviews of the Trust’s quarterly financial statements.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a)(1) Financial Statements
Refer to the Index of Whiting USA Trust I Financial Statements included in Item 8 of this Annual Report on Form 10-K for a list of all financial statements filed as part of this report.
(a)(2) Schedules
Schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.
(a)(3) Exhibits
See Exhibit Index.
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.
March 20, 2015
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
13640 BRIARWICK DRIVE, SUITE 100
306 WEST SEVENTH STREET, SUITE 302
1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1707
FORT WORTH, TEXAS 76102-4987
HOUSTON, TEXAS 77002-5008
512-249-7000
817-336-2461
713-651-9944
www.cgaus.com
January 20, 2015
Whiting USA Trust I
1700 Broadway, Suite 2300
Denver, Colorado 80290-2300
Re:
Evaluation Summary - SEC Price
Whiting USA Trust I Underlying Properties
Proved Producing Reserves
Certain Properties Located in Various States
As of December 31, 2014
Pursuant to the Guidelines of the Securities and
Exchange Commission for Reporting Corporate
Reserves and Future Net Revenue
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 January 31, 2015, which is the estimated date of termination for Whiting USA Trust I. This report, completed January 20, 2015 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.
Hydrocarbon Pricing
As requested for the SEC scenario, initial WTI spot oil and Henry Hub Gas Daily prices of $94.99 per bbl and $4.35 per MMBtu, respectively, were adjusted individually to WTI posted pricing at $91.60 per bbl and Houston Ship Channel pricing at $4.30 per MMBtu, as of December 31, 2014. Further adjustments were applied on a lease level basis for oil price differentials, gas price differentials and heating values as furnished by your office. Prices were not escalated in the SEC scenario. The average adjusted prices used in the estimation of proved producing reserves for the underlying properties full economic life were $82.80 per bbl of oil, $36.75 per bbl of natural gas liquids and $4.39 per mcf of natural gas. For the proved producing reserves of the underlying properties estimated to be produced by January 31, 2015, the average adjusted prices were $83.33 per bbl of oil, $35.34 per bbl of natural gas liquids and $4.48 per mcf of natural gas.
Capital, Expenses and Taxes
Capital expenditures, lease operating expenses and Ad Valorem tax values were forecast as provided by your office. As you explained, the capital costs were based on the most current estimates, lease operating expenses were based on the analysis of historical actual expenses, operating overhead is included for operated properties and no credit or deduction is made for producing overhead paid to the company by other owners of the operated properties. Capital costs and 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.
SEC Conformance and Regulations
The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined on pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
Reserve Estimation Methods
The methods employed in estimating reserves are described in page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.
Miscellaneous
An on-site field inspection of the properties has not been performed. The mechanical operation or conditions of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The costs of plugging and abandonment, less proceeds from the salvage value of equipment and/or facilities, have been included where material.
The reserve estimates were based on interpretations of factual data furnished by your office. 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.
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,
/s/ Robert D. Ravnaas
Robert D. Ravnaas, P.E.
President
Cawley, Gillespie & Associates
Texas Registered Engineering Firm
APPENDIX
Explanatory Comments for Individual Tables
HEADINGS
Table Number
Effective Date of the Evaluation
Identity of Interest Evaluated
Reserve Classification and Development Status
Operator - Property Name
Field (Reservoir) Names - County, State
FORECAST
(Columns)
(1)(11)(21)
Calendar or Fiscal years/months commencing on effective date.
(2)(3)(4)
Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.
(5)(6)(7)
Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.
(8)
Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
(9)
Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
(10)
Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
(12)
Revenue derived from oil sales -- column (5) times column (8).
(13)
Revenue derived from gas sales -- column (6) times column (9).
(14)
Revenue derived from NGL sales -- column (7) times column (10).
(15)
Revenue derived from other sources.
(16)
Revenue derived from hedge positions.
(17)
Total Revenue - sum of column (12) through column (16).
(18)
Production-Severance taxes deducted from gross oil and NGL revenue.
(19)
Production-Severance taxes deducted from gross gas revenue.
(20)
Revenue after taxes - column (17) less column (18) and column (19).
(22)
Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS.
(23)
Ad Valorem taxes.
(24)
Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
(25)
3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
(26)
Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.
(27)
Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
(28)(29)
Future Net Cash Flow is column (18) less the total of column (19), column (22), column (24), column (25), column (26) and column (27). The data in column (28) are accumulated in column (29). Federal income taxes have not been considered.
(30)
Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.
MISCELLANEOUS
Input Data
•
Evaluation parameters such as rates, tax percentages, and expenses are shown below columns (21-26).
Interests
•
Initial and final expense and revenue interests are shown below columns (27-28).
DCF Profile
•
The cash flow discounted at six different rates are shown at the bottom of columns (29-30). Interest has been compounded monthly.
Life
•
The economic life of the appraised property is noted in the lower right-hand corner of the table.
Footnotes
•
Well ID information or other pertinent comments may be shown in the lower left-hand footnotes.
Cawley, Gillespie & Associates, Inc.
Appendix
APPENDIX
Methods Employed in the Estimation of Reserves
The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.
Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.
A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:
Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as “decline curve” analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.
Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.
Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.
Analogy. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.
Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.
Cawley, Gillespie & Associates, Inc.
Appendix
APPENDIX
Reserve Definitions and Classifications
The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:
“(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
“(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
“(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
“(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
“(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
“(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
Cawley, Gillespie & Associates, Inc.
Appendix
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
“(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
“(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
“(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
Cawley, Gillespie & Associates, Inc.
Appendix
“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S-K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”
“(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”
Cawley, Gillespie & Associates, Inc.
Appendix
Cawley, Gillespie & Associates, Inc.
PETROLEUM CONSULTANTS
13640 BRIARWICK DRIVE, SUITE 100
306 WEST SEVENTH STREET, SUITE 302
1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1707
FORT WORTH, TEXAS 76102-4987
HOUSTON, TEXAS 77002-5008
512-249-7000
817-336-2461
713-651-9944
www.cgaus.com
Professional Qualifications of Robert D. Ravnaas, P.E.
President of Cawley, Gillespie & Associates
Mr. Ravnaas has been a Petroleum Consultant for Cawley, Gillespie & Associates (CG&A) since 1983, and became President in 2011. 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
(* Asterisk indicates exhibit previously filed with the SEC and incorporated herein by reference.)