Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
| þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
for the quarterly period ended March 31, 2012
OR
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
for the transition period from to
Commission File Number: 001-35459
WHITING USA TRUST II
(Exact name of registrant as specified in its charter)
| Delaware | 38-7012326 | |||
| (State or other jurisdiction of | (I.R.S. Employer | |||
| incorporation or organization) | Identification No.) | |||
The Bank of New York Mellon Trust Company, N.A., Trustee | ||||
| Global Corporate Trust | ||||
| 919 Congress Avenue | ||||
| Austin, Texas | 78701 | |||
| (Address of principal executive offices) | (Zip Code) | |||
(800) 852-1422
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes¨ Noþ
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes¨ No¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
| Large accelerated filer¨ | Accelerated filer¨ | Non-accelerated filerþ | Smaller reporting company¨ | |||
| (Do not check if a smaller reporting company) | ||||||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes¨ Noþ
As of May 11, 2012, 18,400,000 Units of Beneficial Interest in Whiting USA Trust II were outstanding.
Table of Contents
Table of Contents
GLOSSARY OFCERTAIN DEFINITIONS
The following are definitions of significant terms used in this report:
Bbl— One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil and other liquid hydrocarbons.
BOE— One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals six Mcf of natural gas and one Bbl of crude oil equals one Bbl of natural gas liquids.
Completion— The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
COPAS— The Council of Petroleum Accountants Societies, Inc.
Costless collar— An options position where the proceeds from the sale of a call option at its inception fund the purchase of a put option at its inception.
Differential— The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot, and the wellhead price received.
FASB— Financial Accounting Standards Board.
FASB ASC— The Financial Accounting Standards Board Accounting Standards Codification.
Field— An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
GAAP — Generally accepted accounting principles in the United States of America.
Gross wells —The total wells in which a working interest is owned.
IRS— The Internal Revenue Service of the United States federal government.
MBbl— One thousand barrels of crude oil or other liquid hydrocarbons.
MBOE— One thousand BOE.
Mcf— One thousand standard cubic feet of natural gas.
MMBOE— One million BOE.
MMcf— One million standard cubic feet of natural gas.
Net profits interest (NPI)— A nonoperating interest that creates a share in gross production from an operating or working interest in oil and natural gas properties. The share is measured by net profits from the sale of production after deducting costs associated with that production.
Plugging and abandonment —Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.
Pre-tax PV 10% — The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated lease operating expense, production taxes and future development costs, using price and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, depreciation, depletion and amortization, or Federal income taxes and discounted using an annual discount rate of 10%. Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC.
2
Table of Contents
Proved reserves — Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.
The area of the reservoir considered as proved includes all of the following:
| a. | The area identified by drilling and limited by fluid contacts, if any, and |
| b. | Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. |
Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur:
| a. | Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and |
| b. | The project has been approved for development by all necessary parties and entities, including governmental entities. |
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Reasonable certainty— If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical) engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.
Reserves— Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Reservoir— A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
SEC— The United States Securities and Exchange Commission.
Working interest— The interest in a crude oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to share in production, subject to all royalties, overriding royalties and other burdens and to share in all costs of exploration, development and operations and all risks in connection therewith.
Workover— Operations on a producing well to restore or increase production.
3
Table of Contents
PART I – FINANCIAL INFORMATION
Statements of Assets and Trust Corpus
(Unaudited)
| $193,687,83555 | $193,687,83555 | |||||||
| March 31, 2012 | December 31, 2011 | |||||||
ASSETS | ||||||||
Cash and short-term investments | $ | 10 | $ | 10 | ||||
Investment in net profits interest, net | 193,687,825 | - | ||||||
|
|
|
| |||||
Total assets | $ | 193,687,835 | $ | 10 | ||||
|
|
|
| |||||
TRUST CORPUS | ||||||||
Trust corpus (18,400,000 Trust units issued and outstanding at March 31, 2012) | $ | 193,687,835 | $ | 10 | ||||
|
|
|
| |||||
Statement of Changes inTrust Corpus
(Unaudited)
| Three Months Ended March 31, 2012 | ||||||
Trust corpus, beginning of period | $ | 10 | ||||
Investment in net profits interest | 194,032,491 | |||||
Amortization of investment in net profits interest | (344,666 | ) | ||||
|
| |||||
Trust corpus, end of period | $ | 193,687,835 | ||||
|
| |||||
The accompanying notes are an integral part of these modified cash basis financial statements.
4
Table of Contents
NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS
(Unaudited)
| 1. | ORGANIZATION OF THE TRUST |
Formation of the Trust— Whiting USA Trust II (the “Trust”) is a statutory trust formed on December 5, 2011 under the Delaware Statutory Trust Act, pursuant to a trust agreement (the “Trust agreement”) among Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), as trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”) and Wilmington Trust, National Association, as Delaware Trustee (the “Delaware Trustee”). The initial capitalization of the Trust estate was funded by Whiting Petroleum Corporation (“Whiting”) on December 8, 2011.
The Trust was created to acquire and hold a term net profits interest (“NPI”) for the benefit of the Trust unitholders pursuant to a conveyance from Whiting Oil and Gas, a 100%-owned subsidiary of Whiting, to the Trust. The term NPI is an interest in certain of Whiting Oil and Gas’ properties located in the Rocky Mountains, Permian Basin, Gulf Coast and Mid-Continent regions (the “underlying properties”). The NPI is the only asset of the Trust, other than cash reserves held for future Trust expenses. As of December 31, 2011, these oil and gas properties included interests in approximately 1,300 gross (390.3 net) producing oil and gas wells.
The NPI is passive in nature, and the Trustee has no management control over and no responsibility relating to the operation of the underlying properties. The NPI entitles the Trust to receive 90% of the net proceeds from the sale of production from the underlying properties. The NPI will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), and the Trust will soon thereafter wind up its affairs and terminate, after which it will pay no further distributions.
The Trustee can authorize the Trust to borrow money for the purpose of paying Trust administrative or incidental expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee, Whiting or the Delaware Trustee as a lender, provided that the terms of the loan are similar to the terms it would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself and make other short term investments with the funds distributed to the Trust.
Initial Issuance ofTrust Units and Net Profits Interest Conveyance— On March 21, 2012, the registration statement on Form S-1/S-3 (Registration No. 333-178586) filed by Whiting and the Trust in connection with the initial public offering of the Trust units was declared effective by the SEC. On March 28, 2012, the Trust issued 18,400,000 Trust units to Whiting in exchange for the conveyance of the term NPI from Whiting Oil and Gas, as discussed above. Immediately thereafter, Whiting completed an initial public offering of units of beneficial interest in the Trust, selling 18,400,000 Trust units to the public at $20.00 per Trust unit.
| 2. | BASIS OF ACCOUNTING |
Interim Financial Statements —The accompanying unaudited financial information has been prepared by the Trustee in accordance with the instructions to Form 10-Q. The accompanying financial information is prepared on a comprehensive basis of accounting other than GAAP. The Trustee believes that the information furnished reflects all adjustments (consisting of normal and recurring adjustments) which are, in the opinion of the Trustee, necessary for a fair presentation of the results for the interim periods presented. The financial information should be read in conjunction with the financial statements and notes thereto included in the Prospectus dated March 22, 2012. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.
Term Net Profits Interest —The Trust uses the modified cash basis of accounting to report Trust receipts from the term NPI and payments of expenses incurred. The actual cash distributions to the Trust will be 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; development costs; production and property taxes; payments made by Whiting to the hedge counterparty upon settlements of hedge contracts; maintenance expenses; producing overhead; and amounts that may be reserved for future development, maintenance or operating expenses, which reserve amounts may not exceed $2.0 million; exceed hedge payments received by Whiting under hedge contracts and other non-production revenue) of the underlying properties multiplied by 90% (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.
5
Table of Contents
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 Trustee’s 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 cash earnings; and |
| f) | The Trust evaluates impairment of the investment in net profits interest by comparing the undiscounted cash flows expected to be realized from the investment in net profits interest to the NPI carrying value. If the expected future undiscounted cash flows are less than the carrying value, the Trust recognizes an impairment loss for the difference between the carrying value and the estimated fair value of the investment in net profits interest. The determination of whether the NPI is impaired requires a significant amount of judgment by the Trustee and is based on the best information available to the Trustee at the time of the evaluation. If market or oil and natural gas production conditions deteriorate, write-downs could be required in the future. |
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 were received or expenses were paid. Because the Trust’s financial statements are prepared on the modified cash basis as described above, however, most accounting pronouncements are not applicable to the Trust’s financial statements.
Recent Accounting Pronouncements —There were no accounting pronouncements issued during the quarter ended March 31, 2012 applicable to the Trust or its financial statements.
| 3. | INVESTMENT IN NET PROFITS INTEREST |
Whiting Oil and Gas conveyed the NPI to the Trust in exchange for 18,400,000 Trust units. The NPI is recorded at the historical cost of Whiting on March 28, 2012, the date of the conveyance (except for the derivatives which are reflected at their fair value as of March 31, 2012), and is calculated as follows:
| Three Months Ended March 31, 2012 | ||||||
Oil and gas properties | $ | 368,785,829 | ||||
Accumulated depletion | (174,625,538 | ) | ||||
|
| |||||
Oil and gas properties, net | 194,160,291 | |||||
Derivative liability | (127,800 | ) | ||||
|
| |||||
Net predecessor cost of net profits interest conveyed to the Trust | $ | 194,032,491 | ||||
|
| |||||
As of March 31, 2012, accumulated amortization of the investment in net profits interest was $344,666.
6
Table of Contents
| 4. | INCOME TAXES |
The Trust is a grantor trust and therefore is not subject to federal income taxes. Accordingly no recognition is given to federal income taxes in the Trust’s financial statements. The Trust unitholders are treated as the owners of Trust income and corpus, and the entire taxable income of the Trust is reported by the Trust unitholders on their respective tax returns.
For Montana state income tax purposes, Whiting must withhold from its NPI payments to the Trust, an amount equal to 6% of the net amount payable to the Trust from the sale of oil and gas in Montana. For Arkansas, Colorado, Michigan, Mississippi, New Mexico, North Dakota and Oklahoma, neither the Trust nor Whiting is withholding the income tax due such states on distributions made to an individual resident or nonresident Trust unitholder, as long as the Trust is taxed as a grantor trust under the Internal Revenue Code.
| 5. | DISTRIBUTION TO UNITHOLDERS |
Actual cash distributions to the Trust unitholders depend on the volumes of and prices received for oil, natural gas and natural gas liquids produced from the underlying properties, among other factors. Quarterly cash distributions during the term of the Trust will be made by the Trustee generally no later than 60 days following the end of each quarter (or the next succeeding business day) to the Trust unitholders of record on the 50th day following the end of each quarter. Such amounts will 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 cash reserves established for future expenses of the Trust.
| 6. | RELATED PARTY TRANSACTIONS |
Plugging and Abandonment —During the three months ended March 31, 2012, Whiting incurred $214,644 of plugging and abandonment costs on the underlying properties. Pursuant to the terms of the conveyance agreement, plugging and abandonment charges relating to the underlying properties, net of any proceeds received from the salvage of equipment, are funded entirely by Whiting and are not therefore included as a deduction in the calculation of net proceeds or otherwise deducted from Trust unitholders over the term of the Trust.
Operating Overhead —Pursuant to the terms of its applicable joint operating agreements, Whiting deducts from the gross oil and gas sales proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally, with respect to those underlying properties for which Whiting is the operator but where there is no operating agreement in place, Whiting deducts from the gross proceeds an overhead fee calculated in the same manner that Whiting allocates overhead to other similarly owned properties, which is customary practice in the oil and gas industry. Operating overhead activities include various engineering, legal, and administrative functions. The fee is adjusted annually pursuant to the 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 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.
Trustee Administrative Fee —Under the terms of the Trust agreement, the Trust pays an annual administrative fee to the Trustee of $175,000, which is paid in four quarterly installments of $43,750 each and will be billed in arrears. Starting in 2017, such fee escalates by 2.5% each year.
| 7. | SUBSEQUENT EVENTS |
Initial Distribution to the Trust.On May 7, 2012, the Trustee announced the first Trust distribution of net profits for the first quarterly payment period in 2012. Unitholders of record on May 20, 2012 (which results in an effective record date of May 18, 2012 due to the 20th of May falling on a non-trading day) are expected to receive a distribution amounting to $17,563,791 or $0.954554 per Trust unit, which is payable on or before May 30, 2012. This distribution is expected to consist of net cash proceeds of $18,078,189 paid by Whiting to the Trust, less a provision of $500,000 for estimated Trust expenses and $14,398 for Montana state income tax withholdings. There were no commodity derivative settlements in the first quarterly payment period in 2012.
| 8. | PRO FORMA FINANCIAL STATEMENTS |
The following unaudited pro forma statements of distributable income assume that the conveyance of the term NPI occurred on December 5, 2011, the Trust’s formation date, reflecting only pro forma adjustments that are (i) directly attributable to the transaction, (ii) expected to have a continuing impact on the combined results, and (iii) factually supportable. These unaudited pro forma financial statements are for informational purposes only and do not purport to present the results that would have actually occurred had the NPI conveyance been completed on the assumed date or for the periods presented or which may be realized in the future.
7
Table of Contents
To produce the pro forma financial information, management made certain estimates and assumptions. These estimates are based on the most recently available information. To the extent there are significant changes in these amounts, the assumptions and estimates herein could change significantly. The unaudited pro forma statement of distributable income should be read in conjunction with “Trustee’s Discussion and Analysis of Financial Condition and Results of Operation” included in this Form 10-Q and the historical financial statements of the Trust, including the related notes, included in this Form 10-Q.
WHITING USA TRUST II
Pro Forma Statements of Distributable Income
| December 5 to December 31, 2011 | Three Months Ended March 31, 2012 | |||||||||||
Historical Results | ||||||||||||
Distributable income, as reported | $ | - | $ | - | ||||||||
Pro Forma Adjustments | ||||||||||||
Income from net profits interest | - | (a) | 16,639,582 | (b) | ||||||||
Less: | ||||||||||||
Trust general and administrative expenses | - | (c) | (93,750 | ) (c) | ||||||||
State income tax withholding | - | (20,632 | ) (d) | |||||||||
|
|
|
| |||||||||
Distributable income | $ | - | $ | 16,525,200 | ||||||||
|
|
|
| |||||||||
Distributable income per unit | $ | - | $ | 0.898109 | ||||||||
|
|
|
| |||||||||
| (a) | The Trust uses the modified cash basis of accounting, and revenues are therefore recorded when received. The pro forma statement of distributable income for the period ended December 31, 2011 assumes that the conveyance of the term NPI occurred on December 5, 2011 and that the NPI was effective for oil and gas production from the underlying properties beginning in 2011, but because the initial distribution from Whiting to the Trust is not due until 60 days following the first quarterly period for which the NPI is effective (which these statements assume is the fourth quarter of 2011), there would be no pro forma income from net profits interest received by the Trust on a cash basis and therefore recognized during the period ended December 31, 2011. |
| (b) | The Trust uses the modified cash basis of accounting, and revenues are therefore recorded when received. The pro forma statements of distributable income assume (i) that the conveyance of the term NPI occurred on December 5, 2011, and (ii) that the NPI was effective for oil and gas production from the underlying properties beginning in 2011. Because quarterly cash distributions to the Trust will be made by Whiting no later than 60 days following the end of each quarter, this adjustment assumes that the quarterly distribution to the Trust during the three months ended March 31, 2012 would have occurred by February 29, 2012 (covering net cash proceeds received by Whiting for oil sales from October 1, 2011 through December 31, 2011 and gas sales from September 1, 2011 through November 30, 2011). |
| (c) | The Trust will pay a quarterly administrative fee to Whiting of $50,000 60 days following the end of each quarter and an annual administrative fee to the Trustee of $175,000, which will be paid in four quarterly installments of $43,750 each and will be billed in arrears. Neither Whiting’s nor the Trustee’s administrative fees would have been paid in 2011 given the assumptions underlying these pro forma statements. |
| (d) | For Montana state income tax purposes, Whiting must withhold from its NPI payments to the Trust, an amount equal to 6% of the net amount payable to the Trust from the sale of oil and gas in Montana. For Arkansas, Colorado, Michigan, Mississippi, New Mexico, North Dakota and Oklahoma, neither the Trust nor Whiting will be 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. |
8
Table of Contents
Item 2. Trustee’s Discussion and Analysis of FinancialCondition and Results of Operations.
References to the “Trust” in this document refer to Whiting USA Trust II. References to “Whiting” in this document refer to Whiting Petroleum Corporation and its subsidiaries. References to “Whiting Oil and Gas” in this document refer to Whiting Oil and Gas Corporation, a 100%-owned subsidiary of Whiting Petroleum Corporation.
The following review of the Trust’s financial condition and results of operations should be read in conjunction with the financial statements and notes thereto, as well as the financial statements and notes thereto included in the Prospectus dated March 22, 2012, available on the SEC’s websitewww.sec.gov.
Note Regarding Forward-Looking Statements
This Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this Form 10-Q, including without limitation the statements under “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” are forward-looking statements. No assurance can be given that such expectations will prove to have been correct. When used in this document, the words “believes,” “expects,” “anticipates,” “projects,” “intends” or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this Form 10-Q, could affect the future results of the energy industry in general, and Whiting and the Trust in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:
| • | the effect of changes in commodity prices and conditions in the capital markets; |
| • | uncertainty of estimates of oil and natural gas reserves and production; |
| • | risks incident to the operation and drilling of oil and natural gas wells; |
| • | future production and development costs; |
| • | the inability to access oil and natural gas markets due to market conditions or operational impediments; |
| • | failure of the underlying properties to yield oil or natural gas in commercially viable quantities; |
| • | the effect of existing and future laws and regulatory actions; |
| • | competition from others in the energy industry; |
| • | risks arising out of the hedge contracts; |
| • | inflation or deflation; and |
| • | other risks described under the caption “Risk Factors” in Item 1A of this Form 10-Q. |
All subsequent written and oral forward-looking statements attributable to Whiting or the Trust or persons acting on behalf of Whiting or the Trust are expressly qualified in their entirety by these factors. The Trust assumes no obligation, and disclaims any duty, to update these forward-looking statements.
Overview
The following review of the Trust’s financial condition and results of operations should be read in conjunction with the financial statements and notes thereto. The Trust was formed on December 5, 2011. The conveyance of the NPI, however, did not occur until March 28, 2012. As a result, the Trust did not recognize any income or make any distributions during the quarter ended March 31, 2012. On May 7, 2012, the Trustee announced the first Trust distribution of net profits that is payable on or before May 30, 2012. This expected distribution consists of an amount in cash payable by Whiting for net proceeds generated from the underlying properties since the January 1, 2012 NPI effective date through March 31, 2012.
The Trust does not conduct any operations or activities. The Trust’s purpose is, in general, to hold the NPI, to distribute to the Trust unitholders cash that the Trust receives in respect of the NPI, and to perform certain administrative functions in respect of the
9
Table of Contents
NPI and the Trust units. The Trust derives substantially all of its income and cash flows from the NPI, which is in turn subject to commodity hedge contracts. The NPI entitles the Trust to receive 90% of the net proceeds from the sale of production from the underlying properties.
Oil and gas prices historically have been volatile and may fluctuate widely in the future. The following table highlights these price trends by listing quarterly average NYMEX crude oil and natural gas prices for the periods indicated through December 31, 2011:
| 2010 | 2011 | |||||||||||||||||||||||||||||||
| Q1 | Q2 | Q3 | Q4 | Q1 | Q2 | Q3 | Q4 | |||||||||||||||||||||||||
Crude Oil (per Bbl) | $ | 78.79 | $ | 77.99 | $ | 76.21 | $ | 85.18 | $ | 94.25 | $ | 102.55 | $ | 89.81 | $ | 94.02 | ||||||||||||||||
Natural Gas (per MMBtu) | $ | 5.30 | $ | 4.09 | $ | 4.39 | $ | 3.81 | $ | 4.10 | $ | 4.32 | $ | 4.20 | $ | 3.54 | ||||||||||||||||
Lower oil and gas prices on production from the underlying properties could cause the following: (i) a reduction in the amount of net proceeds to which the Trust is entitled and (ii) a reduction in the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties. Alternatively, higher oil and natural gas prices may potentially result in the following: (i) an increase in the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties and (ii) cash settlement losses on commodity derivatives.
Trust termination.The NPI will terminate on the later to occur of (i) December 31, 2021, or (ii) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), and the Trust will soon thereafter wind up its affairs and terminate, after which it will pay no further distributions. Since the assets of the Trust are depleting assets, a portion of each cash distribution paid on the Trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. As a result, the market price of the Trust units will decline to zero at termination of the Trust.
Results of Trust Operations
Three Months Ended March 31, 2012
The NPI was conveyed to the Trust on March 28, 2012. As such, the Trust did not have any results of operations for the quarter ended March 31, 2012.
Distributable Income.For the quarter ended March 31, 2012, the Trust’s distributable income was zero.
Subsequent Event.On May 7, 2012, the Trustee announced the first Trust distribution of net profits. Unitholders of record on May 20, 2012 (which results in an effective record date of May 18, 2012 due to the 20th of May falling on a non-trading day) are expected to receive a distribution amounting to $17,563,791 or $0.954554 per Trust unit, which is payable on or before May 30, 2012. This amount relates to the net proceeds generated by the underlying properties since the January 1, 2012 NPI effective date through March 31, 2012. This distribution is expected to result in distributable income to the Trust of $17,563,791 during the second quarter of 2012.
Income from Net Profits Interest.For the quarter ended March 31, 2012, the Trust’s income from net profits interest was zero.
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, development costs and cash settlements on commodity derivatives.
10
Table of Contents
Subsequent Event.On May 7, 2012, the Trustee announced the first Trust distribution of net profits, from which the Trust is expected to receive income from net profits interest in the amount of $18,078,189. The following is a summary of the income from net profits interest expected to be received subsequent to the quarter ended March 31, 2012:
Sales volumes: | ||||||
Oil from underlying properties (MBbls) | 301,325 | (a) | ||||
Natural gas from underlying properties (MMcf) | 456,862 | (a) | ||||
|
| |||||
Total production (MBOE) | 377,469 | |||||
Average sales prices: | ||||||
Oil (per Bbl) | $ | 93.00 | ||||
Natural gas (per Mcf) | $ | 5.29 | (b) | |||
Costs (per BOE): | ||||||
Lease operating expenses | $ | 19.26 | ||||
Production taxes | $ | 4.31 | ||||
Revenues: | ||||||
Oil sales | $ | 28,023,551 | (a) | |||
Natural gas sales | 2,417,580 | (a) | ||||
|
| |||||
Total revenues | $ | 30,441,131 | ||||
Costs: | ||||||
Lease operating expenses | $ | 7,268,925 | ||||
Production taxes | 1,628,493 | |||||
Development costs | 1,456,836 | |||||
|
| |||||
Total costs | $ | 10,354,254 | ||||
|
| |||||
Net proceeds | $ | 20,086,877 | ||||
Net profits percentage | 90 | % | ||||
|
| |||||
Income from net profits interest | $ | 18,078,189 | ||||
|
| |||||
| (a) | Oil and gas sales volumes and related revenues (consisting of Whiting’s May 2012 expected NPI distribution to the Trust) generally represent crude oil production from January 2012 through March 2012 and natural gas production from January 2012 through February 2012. |
| (b) | The average sales price of natural gas for the gas production months within the distribution period exceeded the average NYMEX gas prices for those same months within the period due to the “liquids rich” content of a portion of the natural gas volumes produced by the underlying properties. |
Liquidity and Capital Resources
The Trust has no source of liquidity or capital resources other than cash flows from the NPI. Other than Trust administrative expenses, including any reserves established by the Trustee for future liabilities, the Trust’s only use of cash is for distributions to Trust unitholders. Administrative expenses include payments to the Trustee and the Delaware Trustee as well as a quarterly fee to Whiting pursuant to an administrative services agreement. Each quarter, the Trustee determines the amount of funds available for distribution 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. The Trustee may borrow funds required to pay liabilities if the Trustee determines that the cash on hand and the cash to be received are insufficient to cover the Trust’s liabilities. If the Trustee borrows funds, the Trust unitholders will not receive distributions until the borrowed funds are repaid.
Income to the Trust from the NPI is based on the calculation and definitions of “gross proceeds” and “net proceeds” contained in the conveyance agreement, which is listed 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”.
Whiting may reserve from the gross proceeds amounts up to a total of $2.0 million at any time for future development, maintenance or operating expenses. However, Whiting does not anticipate funding such reserve between January 1, 2012 and December 31, 2012, but plans to deduct from the net proceeds only actual costs paid for development, maintenance and operating expenses.
Plugging and abandonment costs related to the underlying properties, net of any proceeds received from the salvage of equipment, cannot be included as a deduction in the calculation of net proceeds pursuant to the terms of the conveyance agreement. Whiting therefore incurred $214,644 of plugging and abandonment charges on the underlying properties during the three months ended March 31, 2012 that were not passed on to the unitholders of the Trust.
11
Table of Contents
Pursuant to the terms of the Trust agreement, Whiting has agreed to post a letter of credit in the amount of $1.0 million in favor of the Trustee to provide a mechanism for the Trustee to pay the operating expenses of the Trust in the unlikely event that Whiting should fail to fund the Trust in the future. This letter of credit will not be used to fund NPI distributions to unitholders.
The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust’s liquidity or the availability of capital resources.
Future Trust Distributions to Unitholders
On May 7, 2012, the Trustee announced the Trust distribution of net profits for the first quarterly payment period in 2012. Unitholders of record on May 20, 2012 (which results in an effective record date of May 18, 2012 due to the 20th of May falling on a non-trading day) are expected to receive a distribution amounting to $17,563,791 or $0.954554 per Trust unit, which is payable on or before May 30, 2012. This distribution is expected to consist of net cash proceeds of $18,078,189 paid by Whiting to the Trust, less a provision of $500,000 for estimated Trust expenses and $14,398 for Montana state income tax withholdings. There were no commodity derivative settlements in the first quarterly payment period of 2012.
New Accounting Pronouncements
There were no accounting pronouncements issued during the three months ended March 31, 2012 applicable to the Trust or its financial statements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Hedge Contracts
The primary asset of and source of income to the Trust is the term NPI, which generally entitles the Trust to receive 90% of the net proceeds from oil and gas production from the underlying properties. Consequently, the Trust is exposed to market risk from fluctuations in oil and gas prices. Through 2014, however, the NPI is subject to commodity hedge contracts in the form of costless collars entered into by Whiting, which reduce its exposure to crude oil price volatility. No additional hedges are allowed to be placed on Trust assets, and the Trust cannot therefore enter into derivative contracts for speculative or trading purposes.
The revenues derived from the underlying properties depend substantially on prevailing crude oil, natural gas and natural gas liquids prices. As a result, commodity prices also affect the amount of cash flow available for distribution to the Trust unitholders. Lower prices may also reduce the amount of oil, natural gas and natural gas liquids that Whiting can economically produce. Whiting sells the oil, natural gas and natural gas liquid production from the underlying properties under floating market price contracts each month. Whiting has entered into certain hedge contracts from April 1, 2012 through December 31, 2014 to manage the exposure to crude oil price volatility, which is associated with revenues generated from the underlying properties, and to achieve more predictable cash flows. However, these contracts limit the amount of cash available for distribution if prices increase above the fixed ceilings of the hedges. The hedge contracts consist of costless collar arrangements placed with a single trading counterparty, JPMorgan Chase Bank National Association. Whiting cannot provide assurance that this trading counterparty will not become a credit risk in the future.
Crude oil costless collar arrangements settle based on the average of the closing settlement price for each commodity business day in the contract period. In a collar arrangement, the counterparty is required to make a payment to Whiting for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. Whiting is required to make a payment to the hedge counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price.
In connection with Whiting’s conveyance on March 28, 2012 of the term NPI to the Trust, the rights to any future hedge payments Whiting makes or receives on certain of its derivative contracts (representing 1,459 MBbls of crude oil from 2012 through 2014) have also been conveyed to the Trust. As a result, such hedge payments will be included in the Trust’s calculation of net proceeds, and Trust unitholders thereby receive 90% of the future economic results of such hedges.
The table below summarizes all of the outstanding costless collars that Whiting entered into and then in turn conveyed, as described in the preceding paragraph, to the Trust (of which Trust unitholders receive 90% of the future economic results). This quantity of hedged oil volumes represents approximately 45% of the underlying properties’ oil production from April 2012 through 2014, based on the estimated production of proved reserves as projected in the Trust’s December 31, 2011 reserve report.
12
Table of Contents
| Oil Collars | ||||
| Volumes (Bbls) | Weighted Average Price (per Bbl) Floor / Ceiling | |||
Three months ending June 30, 2012 | 145,200 | $80.00/$122.50 | ||
Three months ending September 30, 2012 | 143,700 | $80.00/$122.50 | ||
Three months ending December 31, 2012 | 140,400 | $80.00/$122.50 | ||
Three months ending March 31, 2013 | 136,800 | $80.00/$122.50 | ||
Three months ending June 30, 2013 | 136,500 | $80.00/$122.50 | ||
Three months ending September 30, 2013 | 133,500 | $80.00/$122.50 | ||
Three months ending December 31, 2013 | 130,200 | $80.00/$122.50 | ||
Three months ending March 31, 2014 | 127,500 | $80.00/$122.50 | ||
Three months ending June 30, 2014 | 124,500 | $80.00/$122.50 | ||
Three months ending September 30, 2014 | 121,800 | $80.00/$122.50 | ||
Three months ending December 31, 2014 | 119,100 | $80.00/$122.50 | ||
The collared hedges shown above have the effect of providing a protective floor while allowing Trust unitholders to share in upward price movements up to the ceiling. Consequently, while these hedges are designed to decrease exposure to price decreases, they also have the effect of limiting the benefit of price increases beyond the ceiling. For the crude oil contracts listed above, a hypothetical $10.00 change in the NYMEX price above the ceiling price or below the floor price applied to the notional amounts would cause an aggregate change in the cash settlement payments (gains received) on all oil commodity derivatives of $14.6 million to Whiting, of which 90% would be transferred to the Trust. These hypothetical cash settlement payments (gains received) would be recognized as contracts expire in future periods through 2014.
The amounts received by Whiting from the counterparty upon settlements of these hedge contracts will reduce the production and development costs related to the underlying properties when calculating the net proceeds. However, if the hedge payments received by Whiting under the hedge contracts and other non-production revenue exceed production and development costs during a quarterly period, the ability to use such excess amounts to offset such costs may be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period where the hedge payments and the other non-production revenue are less than such costs. In addition, the aggregate amounts paid by Whiting on settlement of the hedge contracts will reduce the amount of net proceeds paid to the Trust.
Item 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures.The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and regulations promulgated by the SEC. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by Whiting to The Bank of New York Mellon Trust Company, N.A., as Trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, the Trustee carried out an evaluation of the Trustee’s disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.
Due to the contractual arrangements of (i) the Trust agreement and (ii) the conveyance of the NPI, the Trustee relies on (A) information provided by Whiting, including historical operating data, plans for future operating and capital expenditures, reserve information and information relating to projected production, and (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers. For a description of certain risks relating to these arrangements and risks relating to the Trustee’s reliance on information reported by Whiting and included in the Trust’s results of operations, see Item 1A. Risk Factors “The Trust and the Trust unitholders have no voting or managerial rights with respect to the underlying properties. As a result, neither the Trust nor the unitholders have any ability to influence the operation of the underlying properties” included in this Quarterly Report on Form 10-Q.
Changes in Internal Control over Financial Reporting.During the quarter ended March 31, 2012, except for the establishment of internal control over financial reporting in connection with the formation of the Trust, 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.
13
Table of Contents
| Item 1A. | Risk Factors |
The amounts of cash distributions by the Trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquids prices, subject to the hedge contracts. The hedge contracts will limit the potential for increases in cash distributions due to oil price increases from April 1, 2012 through December 31, 2014.
The reserves attributable to the underlying properties and the quarterly cash distributions of the Trust are highly dependent upon the prices realized from the sale of oil, natural gas and natural gas liquids. Prices of oil, natural gas and natural gas liquids applicable to the underlying properties can fluctuate widely on a quarter-to-quarter basis in response to a variety of factors that are beyond the control of the Trust and Whiting. These factors include, among others:
| • | changes in regional, domestic and global supply and demand for oil and natural gas; |
| • | the actions of the Organization of Petroleum Exporting Countries; |
| • | the price and quantity of imports of foreign oil and natural gas; |
| • | political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity, such as recent conflicts in the Middle East; |
| • | the level of global oil and natural gas exploration and production activity; |
| • | the effects of global credit, financial and economic issues; |
| • | the level of global oil and natural gas inventories; |
| • | developments of United States energy infrastructure, such as the recent announcement of the planned reversal of the Seaway pipeline from Cushing, Oklahoma to the Gulf Coast and the development of liquefied natural gas exporting facilities and the perceived timing thereof; |
| • | weather conditions; |
| • | technological advances affecting energy consumption; |
| • | domestic and foreign governmental regulations; |
| • | proximity and capacity of oil and natural gas pipelines and other transportation facilities; |
| • | the price and availability of competitors’ supplies of oil and gas in captive market areas; |
| • | the price and availability of alternative fuels; and |
| • | acts of force majeure. |
Moreover, government regulations, such as regulation of oil and natural gas gathering and transportation, can adversely affect commodity prices in the long term.
Whiting has entered into hedge contracts, which are structured as costless collar arrangements that will hedge approximately 45% of the crude oil volumes expected to be produced from the underlying properties through December 31, 2014. These hedge contracts, however, only cover a portion of the oil volumes and none of the natural gas or natural gas liquids volumes that are expected to be produced during such period. Because of the differential between NYMEX or other benchmark prices of oil and natural gas and the wellhead price received, hedge contracts may not totally offset the effects of price fluctuations. Whiting has not entered into any hedge contracts relating to oil, natural gas or natural gas liquids expected to be produced after 2014, and the terms of the conveyance of the NPI will prohibit Whiting from entering into any new hedging arrangements. As a result, the amounts of the cash distributions may fluctuate significantly after 2014 as a result of changes in commodity prices because there will be no hedge contracts in place to reduce the Trust’s exposure to oil and natural gas price volatility. The hedge contracts may also limit the amount of cash available for distribution if oil prices increase. In addition, the hedge contracts are subject to the nonperformance of the counterparty and other risks. For a discussion of the hedge contracts, see “Quantitative and Qualitative Disclosures About Market Risk” in Item 3 of this Quarterly Report on Form 10-Q.
Lower prices of oil, natural gas and natural gas liquids will reduce the amount of the net proceeds to which the Trust is entitled and may ultimately reduce the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties. As a result, the operator of any of the underlying properties could determine during periods of low commodity prices to shut in or curtail production from the underlying properties. In addition, the operator of these properties could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Because these properties are mature, decreases in commodity prices could have a
14
Table of Contents
more significant effect on the economic viability of these properties as compared to more recently discovered properties. The commodity price sensitivity of these mature wells is due to a culmination of factors that vary from well to well, including the additional costs associated with water handling and disposal, chemicals, surface equipment maintenance, downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result, the volatility of commodity prices may cause the amount of future cash distributions to Trust unitholders to fluctuate, and a substantial decline in the price of oil, natural gas or natural gas liquids will likely materially reduce the amount of cash available for distribution to the Trust unitholders.
Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the Trust units.
The value of the Trust units and the amount of future cash distributions to the Trust unitholders will depend upon, among other things, the accuracy of the production and reserves estimated to be attributable to the underlying properties and the NPI. Estimating production and reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates, and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating production and reserves. Those factors and assumptions include:
| • | historical production from the area compared with production rates from other producing areas; |
| • | the assumed effect of governmental regulation; and |
| • | assumptions about future prices of oil, natural gas and natural gas liquids, including differentials, production and development costs, gathering and transportation costs, severance and excise taxes and capital expenditures. |
Changes in these assumptions may materially alter production and reserve estimates. The estimated proved reserves attributable to the NPI and the pre-tax PV10% value attributable to the NPI are based on estimates of reserve quantities and revenues for the underlying properties. The quantities of reserves attributable to the underlying properties and the NPI may decrease in the future as a result of future decreases in the price of oil, natural gas or natural gas liquids.
Risks associated with the production, gathering, transportation and sale of oil, natural gas and natural gas liquids could adversely affect cash distributions by the Trust and the value of the Trust units.
The revenues of the Trust, the value of the Trust units and the amount of cash distributions to the Trust unitholders will depend upon, among other things, oil, natural gas and natural gas liquids production and prices and the costs incurred to exploit oil and natural gas reserves attributable to the underlying properties. Drilling, production or transportation accidents that temporarily or permanently halt the production and sale of oil, natural gas and natural gas liquids at any of the underlying properties will reduce Trust distributions by reducing the amount of net proceeds available for distribution. For example, accidents may occur that result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any costs incurred in connection with any such accidents that are not insured against will have the effect of reducing the net proceeds available for distribution to the Trust. Also, Whiting does not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. In addition, curtailments or damage to pipelines used to transport oil, natural gas and natural gas liquids production to markets for sale could reduce the amount of net proceeds available for distribution. Any such curtailment or damage to the gathering systems could also require finding alternative means to transport the oil, natural gas and natural gas liquids production from the underlying properties, which alternative means could result in additional costs that will have the effect of reducing net proceeds available for distribution.
Also, drilling, production and transportation of hydrocarbons bear an inherent risk of loss of containment. Potential consequences include loss of reserves, loss of production, loss of economic value associated with the affected wellbore, contamination of soil, ground water, and surface water, as well as potential fines, penalties or damages associated with any of the foregoing consequences.
The processes of drilling and completing wells are high risk activities.
The processes of drilling and completing wells are subject to numerous risks beyond the Trust’s and Whiting’s control, including risks that could delay the current drilling schedule of Whiting or any other operator of an underlying property and the risk that drilling will not result in commercially viable production. Neither Whiting nor any other operator is obligated to undertake any development activities, so any drilling and completion activities will be subject to their reasonable discretion. Further, Whiting’s or any other operator’s future business, financial condition, results of operations, liquidity or ability to finance its share of planned development expenditures could be materially and adversely affected by any factor that may curtail, delay or cancel drilling, including the following:
| • | delays imposed by or resulting from compliance with regulatory requirements; |
15
Table of Contents
| • | pressure or irregularities in geological formations; |
| • | shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs, completion services and CO2; |
| • | equipment failures or accidents; |
| • | adverse weather conditions, such as freezing temperatures, hurricanes and storms; |
| • | reductions in oil, natural gas and natural gas liquids prices; |
| • | pipeline takeaway and refining and processing capacity; and |
| • | title problems. |
In the event that development activities are delayed or cancelled, or development wells have lower than anticipated production, due to one or more of the factors above or for any other reason, estimated future distributions to unitholders may be reduced.
The Trust and the Trust unitholders will have no voting or managerial rights with respect to the underlying properties. As a result, neither the Trust nor the Trust unitholders will have any ability to influence the operation of the underlying properties.
Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners of oil and natural gas properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. Neither the Trustee nor the Trust unitholders have any contractual ability to influence or control the field operations of, and sale of oil and natural gas from, the underlying properties, including underlying properties where Whiting is the operator. Also, the Trust unitholders have no voting rights with respect to the operators of these properties and, therefore, will have no managerial, contractual or other ability to influence the activities of the operators of these properties.
Whiting has limited control over activities on the underlying properties that Whiting does not operate, which could reduce production from the underlying properties, increase capital expenditures and reduce cash available for distribution to Trust unitholders.
Whiting is currently designated as the operator of approximately 56% of the underlying properties based on the December 31, 2011 pre-tax PV10% value contained in the reserve report prepared by the Trust’s independent petroleum engineer dated as of December 31, 2011 (the “reserve report”). However, for the 44% of the underlying properties that it does not operate, Whiting does not have control over normal operating procedures or expenditures relating to such properties. The failure of an operator to adequately perform operations or an operator’s breach of the applicable agreements could reduce production from the underlying properties and the cash available for distribution to Trust unitholders. The success and timing of operational activities on properties operated by others therefore depends upon a number of factors outside of Whiting’s control, including the operator’s decisions with respect to the timing and amount of capital expenditures, the period of time over which the operator seeks to generate a return on capital expenditures, the inclusion of other participants in drilling wells, and the use of technology, as well as the operator’s expertise and financial resources and the operator’s relative interest in the underlying field. Operators may also opt to decrease operational activities following a significant decline in oil prices. Because Whiting does not have a majority interest in most of the non-operated properties comprising the underlying properties, Whiting may not be in a position to remove the operator in the event of poor performance. Accordingly, while Whiting has agreed to use commercially reasonable efforts to cause the operator to act as a reasonably prudent operator, it will be limited in its ability to do so.
Shortages or increases in costs of oil field equipment, services, qualified personnel and supply materials could delay production, thereby reducing the amount of cash available for distribution.
The demand for qualified and experienced field personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Additionally, operations on the underlying properties in some instances require supply materials such as CO2 for production which could become subject to shortage and increasing costs. Shortages of field personnel, equipment or supply materials or price increases could significantly decrease the amount of cash available for distribution to the Trust unitholders, or restrict operations on the underlying properties.
16
Table of Contents
Whiting or other operators may abandon individual wells or properties that it or they reasonably believe to be uneconomic.
Whiting or other operators may abandon any well if it or they reasonably believe that the well can no longer produce oil or natural gas in commercially economic quantities. This could result in termination of the NPI relating to the abandoned well.
The reserves attributable to the underlying properties are depleting assets and production from those reserves will diminish over time. Furthermore, the Trust is precluded from acquiring other oil and natural gas properties or NPI to replace the depleting assets and production.
The net proceeds payable to the Trust from the NPI are derived from the sale of oil, natural gas and natural gas liquids produced from the underlying properties and proceeds, if any, received by Whiting upon settlement of the hedge contracts. The reserves attributable to the underlying properties are depleting assets, which means that the reserves attributable to the underlying properties will decline over time. The reserve report reflects that the cumulative past production from the underlying properties through December 31, 2011 represents an aggregate depletion percentage of 86.1% of the estimated ultimate total production from the properties. As a result, the quantity of oil and natural gas produced from the underlying properties is expected to decline over time. As of December 31, 2011, the percentage of remaining reserves expected to be produced during the term of the NPI was 64.5%. The reserves attributable to the underlying properties declined 10.1% from December 31, 2010 to December 31, 2011, and the production attributable to the underlying properties declined 8.9% for the year ended December 31, 2011 as compared to the year ended December 31, 2010. Based on the reserve report, overall production for both oil and gas attributable to the underlying properties is expected to decline at an average year-over-year rate of approximately 8.4% between 2012 and 2021, assuming the level of development drilling and development expenditures on the underlying properties through 2014 disclosed in the prospectus dated March 22, 2012, and none thereafter. However, cash distributions to unitholders may decline at a faster rate than the rate of production due to fixed and semi-variable costs attributable to the underlying properties or if expected future development is delayed, reduced or cancelled. Also, the anticipated rate of decline is an estimate and actual decline rates will likely vary from those estimated. The NPI will terminate on the later to occur of (1) December 31, 2021, or (2) the time when the 11.79 MMBOE has been produced from the underlying properties and sold (which is the equivalent of 10.61 MMBOE in respect to the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI).
Future maintenance projects on the underlying properties beyond those which are currently estimated may affect the quantity of proved reserves that can be economically produced from the underlying properties. The timing and size of these projects will depend on, among other factors, the market prices of oil, natural gas and natural gas liquids. If operators of the underlying properties do not implement required maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by Whiting or estimated in the reserve report. Additionally, Whiting does not own any Trust units, which could reduce its incentive to operate the underlying properties in an efficient and cost-effective manner.
The Trust agreement will provide that the Trust’s business activities will be limited to owning the NPI and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyance related to the NPI. As a result, the Trust will not be permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets and production attributable to the NPI and will not be permitted to enter into any new hedging arrangements.
Because the net proceeds payable to the Trust are derived from the sale of depleting assets, the portion of the distributions to unitholders attributable to depletion should be considered a return of capital as opposed to a return on investment. Eventually, the NPI may cease to produce in commercial quantities and the Trust may, therefore, cease to receive any distributions of net proceeds therefrom.
The amount of cash available for distribution by the Trust will be reduced by the amount of any costs, expenses and reserves related to the underlying properties and other costs and expenses incurred by the Trust.
The NPI will bear its share of all production and development costs and expenses related to the underlying properties, such as lease operating expenses, production and property taxes, development costs and hedge expenses, which will reduce the amount of cash received by the Trust and thereafter distributable to Trust unitholders. Additionally, amounts may be reserved by Whiting for future development, maintenance or operating expenses (which reserve amounts may not exceed $2.0 million), which will also reduce the amount of cash received by the Trust and thereafter distributable to Trust unitholders. Accordingly, higher production and development costs and expenses related to the underlying properties will directly decrease the amount of cash received by the Trust in respect of its NPI. In addition, cash available for distribution by the Trust will be further reduced by the Trust’s general and administrative expenses, which are expected to be $1.0 million in 2012.
If production and development costs on the underlying properties exceed proceeds of production, the Trust will not receive net proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest during the deficit period. If the Trust does not receive net proceeds pursuant to the NPI, or if such net proceeds are reduced, the Trust will not be able to distribute cash to the Trust unitholders, or such cash distributions will be reduced, respectively.
17
Table of Contents
An increase in the differential or decrease in the premium between the NYMEX or other benchmark price of oil and natural gas and the wellhead price received could reduce cash distributions by the Trust and the value of Trust units.
Oil and natural gas production from the underlying properties is usually sold at a discount, but sometimes at a premium to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. A negative difference between the benchmark price and the price received is called a differential and a positive difference is called a premium. The differential and premium may vary significantly due to market conditions, the quality and location of production and other risk factors. Whiting cannot accurately predict oil and natural gas differentials and premiums. Increases in the differential or decreases in the premiums between the benchmark price for oil and natural gas and the wellhead price received could reduce cash distributions by the Trust and the value of Trust units.
Financial returns to purchasers of Trust units will vary in part based on how quickly 11.79 MMBOE are produced from the underlying properties and sold, and it is not known when that will occur.
The NPI will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold. The reserve report projects that 11.79 MMBOE will have been produced from the underlying properties and sold by December 31, 2021. However, the exact rate of production cannot be predicted with certainty and such amount may be produced before or after that date. If production attributable to the underlying properties is slower than estimated, then financial returns to purchasers of Trust units will be lower (assuming commodity prices are consistent with projections) because cash distributions attributable to such production will occur at a later date.
If the payments received by Whiting under the hedge contracts and certain other non-production revenue exceed production and development costs during a quarterly period, then the use of such excess amounts to offset production and development costs will be deferred until the next quarterly period when such amounts are less than such costs.
If the hedge payments received by Whiting and certain other non-production revenue exceed the production and development costs during a quarterly period, the ability to use such excess amounts to offset production and development costs will be deferred until the next quarterly period when such amounts are less than such costs. If such amounts are deferred, then the applicable quarterly distribution will be less than it would have otherwise been. However, if any excess amounts have not been used to offset costs at the time when the NPI terminates, then unitholders will not be entitled to receive the benefit of such excess amounts. Such a scenario could occur if oil prices decline significantly through December 31, 2014 and remained low for the remainder of the term.
The Trust units may lose value as a result of title deficiencies with respect to the underlying properties.
The existence of a material title deficiency with respect to the underlying properties could reduce the value of a property or render it worthless, thus adversely affecting the NPI and distributions to Trust unitholders. Whiting does not obtain title insurance covering mineral leaseholds, and Whiting’s failure to cure any title defects may cause Whiting to lose its rights to production from the underlying properties. In the event of any such material title problem, proceeds available for distribution to Trust unitholders and the value of the Trust units may be reduced.
Under certain circumstances, the Trust provides that the Trustee may be required to sell the NPI and dissolve the Trust prior to the expected termination of the Trust. As a result, Trust unitholders may not recover their investment.
The Trustee must sell the NPI if the holders of a majority of the Trust units approve the sale or vote to dissolve the Trust. The Trustee must also sell the NPI if the annual gross proceeds attributable to the NPI are less than $2.0 million for each of any two consecutive years. The sale of the NPI will result in the dissolution of the Trust. The net proceeds of any such sale will be distributed to the Trust unitholders.
The NPI will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI). The Trust unitholders will not be entitled to receive any net proceeds from the sale of production from the underlying properties following the termination of the NPI. Therefore, the market price of the Trust units will likely diminish towards the end of the term of the NPI because the cash distributions from the Trust will cease at the termination of such NPI and the Trust will have no right to any additional production from the underlying properties after the term of the NPI.
18
Table of Contents
The market price for the Trust units may not reflect the value of the NPI held by the Trust and, in addition, over time will decline to zero at termination of the Trust.
The trading price for publicly traded securities similar to the Trust units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the Trust will vary in response to numerous factors outside the control of the Trust, including prevailing sales prices of oil, natural gas and natural gas liquids production attributable to the underlying properties. Consequently, the market price for the Trust units may not necessarily be indicative of the value that the Trust would realize if it sold the NPI to a third-party buyer. In addition, such market price may not necessarily reflect the fact that since the assets of the Trust are depleting assets, a portion of each cash distribution paid on the Trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. As a result, distributions made to a unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the unitholder, and over time the market price of the Trust units will decline to zero at termination of the Trust.
Conflicts of interest could arise between Whiting and the Trust unitholders.
The interests of Whiting and the interests of the Trust and the Trust unitholders with respect to the underlying properties could at times differ. For example:
| • | Whiting’s interests may conflict with those of the Trust and the Trust unitholders in situations involving the development, maintenance, operation or abandonment of certain wells on the underlying properties for which Whiting acts as the operator. Whiting may also make decisions with respect to development costs that adversely affect the underlying properties. These decisions include reducing development costs on properties for which Whiting acts as the operator, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future. Additionally, Whiting’s broad discretion over the timing and amount of development, maintenance, operating expenditures and activities could result in higher costs being attributed to the NPI. |
| • | Whiting has the right, subject to significant limitations as described herein, to cause the Trust to release a portion of the NPI in connection with a sale of a portion of the oil and natural gas properties comprising the underlying properties to which such NPI relates. In such an event, the Trust is entitled to receive its proportionate share of the proceeds from the sale attributable to the NPI released. |
| • | The Trust has no employees and is reliant on Whiting’s employees to operate those underlying properties for which Whiting is designated as the operator. Whiting’s employees are also responsible for the operation of other oil and gas properties Whiting owns, which may require a significant portion or all of their time and resources. |
The documents governing the Trust generally do not provide a mechanism for resolving these conflicting interests.
The Trust is managed by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.
The business and affairs of the Trust will be managed by the Trustee. The voting rights of a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The Trust agreement provides that the Trustee may only be removed and replaced by a vote of the holders of a majority of the outstanding Trust units at a special meeting of Trust unitholders called by either the Trustee or the holders of not less than 10% of the outstanding Trust units. As a result, it may be difficult to remove or replace the Trustee.
Trust unitholders have limited ability to enforce provisions of the NPI.
The Trust agreement permits the Trustee to sue Whiting on behalf of the Trust to enforce the terms of the conveyance creating the NPI. If the Trustee does not take appropriate action to enforce provisions of the conveyance, your recourse as a Trust unitholder would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The Trust agreement expressly limits the Trust unitholders’ ability to directly sue Whiting or any other third party other than the Trustee. As a result, the unitholders will not be able to sue Whiting to enforce these rights.
19
Table of Contents
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 will be entitled to the same limitation of personal liability extended to stockholders of private corporations under the General Corporation Law of the State of Delaware. Courts in jurisdictions outside of Delaware, however, may not give effect to such limitation.
The operations of the underlying properties may result in significant costs and liabilities with respect to environmental and operational safety matters, which could reduce the amount of cash available for distribution to Trust unitholders.
Significant costs and liabilities can be incurred as a result of environmental and safety requirements applicable to the oil and natural gas exploration, development and production activities of the underlying properties. These costs and liabilities could arise under a wide range of federal, regional, state and local environmental and safety laws, regulations, and enforcement policies, which legal requirements have tended to become increasingly strict over time. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts on the operations of the underlying properties.
Strict, joint and several liability may be imposed under certain environmental laws and regulations, which could result in liability being imposed on Whiting with respect to its portion of the underlying properties due to the conduct of others or from Whiting’s actions even if such actions were in compliance with all applicable laws at the time those actions were taken. Private parties, including the surface estate owners of the real properties at which the underlying properties are located and the owners of facilities where petroleum hydrocarbons or wastes resulting from operations at the underlying properties are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damages. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If it were not possible to recover the resulting costs for such liabilities or non-compliance through insurance or increased revenues, then these costs could have a material adverse effect on the cash distributions to the Trust unitholders.
The Trust bears 90% of all costs and expenses paid by Whiting, including those related to environmental compliance and liabilities associated with the underlying properties. In addition, as a result of the increased cost of compliance, the operators of the underlying properties may decide to discontinue drilling.
The operations of the underlying properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the cash distributions to the Trust unitholders.
The development and production operations of the underlying properties are subject to complex and stringent laws and regulations. In order to conduct the operations of the underlying properties in compliance with these laws and regulations, Whiting and the other operators must obtain and maintain numerous permits, approvals and certificates from various federal, state, local and governmental authorities. Whiting and the other operators may incur substantial costs and experience delays in order to maintain compliance with these existing laws and regulations, which could decrease the cash distributions to the Trust unitholders. In addition, the costs of compliance may increase or the operations of the underlying properties may be otherwise adversely affected if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to such operations. Such costs could have a material adverse effect on the cash distributions to the Trust unitholders.
The operations of the underlying properties are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on the cash distributions to the Trust unitholders.
Climate change legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for oil and gas which could reduce the amount of cash available for distribution to Trust unitholders.
On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. Based on these findings, the EPA has begun adopting and implementing regulations that restrict emissions of GHG under existing provisions of the federal Clean Air Act (“CAA”), including one rule that limits emissions of GHG from motor vehicles beginning with the 2012 model year. The EPA has
20
Table of Contents
asserted that these final motor vehicle GHG emission standards trigger the CAA construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Further, facilities required to obtain PSD permits for their GHG emissions are required to reduce those emissions consistent with guidance for determining “best available control technology” standards for GHG, which guidance was published by the EPA in November 2010. Also in November 2010, the EPA expanded its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis with reporting beginning in 2012 for emissions occurring in 2011. The underlying properties are subject to these reporting requirements.
In addition, both houses of Congress have considered legislation to reduce emissions of GHG, and many states have already taken legal measures to reduce emissions of GHG, primarily through the development of GHG inventories, greenhouse gas permitting and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. In the absence of new legislation, the EPA is issuing new regulations that limit emissions of GHG associated with the operations of the underlying properties which will require Whiting to incur costs to inventory and reduce emissions of GHG associated with the operations of the underlying properties and could adversely affect demand for the oil and natural gas produced. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on the Trust’s assets and the amount of cash available for distribution to the Trust unitholders.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect Whiting’s services.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing has been utilized during the completion of wells drilled on the underlying properties, and Whiting believes that it may also be used in the future. The process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel under the Safe Drinking Water Act’s Underground Injection Control Program and has commenced drafting guidance for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel. Industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with initial results of the study anticipated to be available by late 2012 and final results by 2014. Moreover, the EPA recently announced in October 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy (“DOE”), the U.S. Government Accountability Office and the White House Council for Environmental Quality. The U.S. Department of the Interior is also considering regulation of hydraulic fracturing activities on public lands. In addition, legislation called the Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. For example, on June 17, 2011, Texas enacted a law that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production) and the public. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment including groundwater. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays, litigation risk and potential increases in costs. Further, at least three local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities. No assurance can be given as to whether or not similar measures might be considered or implemented in the jurisdictions in which the underlying properties are located. If new laws or regulations that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in the states where the underlying properties are located, such legal requirements could make it more difficult or costly for Whiting to carry out hydraulic fracturing activities on the underlying properties and thereby could affect the determination of whether a well is commercially viable. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that Whiting is ultimately able to produce in commercially paying quantities from the underlying properties.
21
Table of Contents
The Trust’s NPI may be characterized as an executory contract in bankruptcy, which could be rejected in bankruptcy, thus relieving Whiting from its obligations to make payments to the Trust with respect to the NPI.
Whiting has recorded the conveyance of the NPI in the states where the underlying properties are located in the real property records in each county where these properties are located. The NPI is a non-operating, non-possessory interest carved out of the oil and natural gas leasehold estate, but certain states have not directly determined whether a NPI is a real or a personal property interest. Whiting believes that the delivery and recording of the conveyance should create a fully conveyed and vested property interest under the applicable state’s laws, but certain states have not directly determined whether this would be the result. If in a bankruptcy proceeding in which Whiting becomes involved as a debtor a determination were made that the conveyance constitutes an executory contract and the NPI is not a fully conveyed property interest under the laws of the applicable state, and if such contract were not to be assumed in a bankruptcy proceeding involving Whiting, the Trust would be treated as an unsecured creditor of Whiting with respect to such NPI in the pending bankruptcy proceeding.
If the financial position of Whiting degrades in the future, Whiting may not be able to satisfy its obligations to the Trust.
Whiting operates approximately 56% of the underlying properties based on the December 31, 2011 pre-tax PV10% value. The conveyance provides that Whiting will be obligated to market, or cause to be marketed, the production related to underlying properties for which it operates. In addition, Whiting is obligated to use the proceeds it receives upon the settlement of the hedge contracts to offset operating expenses relating to the underlying properties, with certain restrictions.
Whiting has entered into hedge contracts, consisting of costless collar arrangements, with JPMorgan Chase Bank National Association to reduce the exposure of the revenue from oil production from the underlying properties to fluctuations in crude oil prices in order to achieve more predictable cash flow. The crude oil collar arrangements settle based on the average of the settlement price for each commodity business day in the contract period. In a collar arrangement, the counterparty is required to make a payment to Whiting for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. Whiting is required to make a payment to the counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price. For a detailed description of the terms of these hedge contracts, please read “Quantitative and Qualitative Disclosures About Market Risk” in Item 3 of this Quarterly Report on Form 10-Q.
Whiting’s ability to perform its obligations related to the operation of the underlying properties, its obligations to the counterparty related to the hedge contracts and its obligations to the Trust will depend on Whiting’s future financial condition and economic performance, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and upon financial, business and other factors, many of which are beyond the control of Whiting. Whiting cannot provide any assurance that its financial condition and economic performance will not deteriorate in the future. A substantial or extended decline in oil or natural gas prices may materially and adversely affect Whiting’s future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
The Trust’s receipt of payments based on the hedge contracts depends upon the financial position of the hedge contract counterparty and Whiting. A default by the hedge contract counterparty or Whiting could reduce the amount of cash available for distribution to the Trust unitholders.
In the event that the counterparty to the hedge contracts defaults on its obligations to make payments to Whiting under the hedge contracts, the cash distributions to the Trust unitholders could be materially reduced as the hedge payments are intended to provide additional cash to the Trust during periods of lower crude oil prices. In addition, because the hedge contracts are with a single counterparty, JPMorgan Chase Bank National Association, the risk of default is concentrated with one financial institution. Whiting cannot provide any assurance that this counterparty will not become a credit risk in the future. The hedge contracts also have default terms applicable to Whiting, including customary cross default provisions. If Whiting were to default, the counterparty to the hedge contracts could terminate the hedge contracts and the cash distributions to Trust unitholders could be materially reduced during periods of lower crude oil prices.
The financial results of the Trust may differ from the financial results of Whiting USA Trust I.
As disclosed in the prospectus dated March 22, 2012, Whiting previously participated in the formation and initial public offering of Whiting USA Trust I on April 30, 2008. Given the differences in assets comprising the underlying properties, commodity prices, production and development costs, development schedule, operators of the underlying properties and regulatory environment, among other things, the historical results of operations of the 2008 Trust should not be relied on as an indicator of how Whiting USA Trust II will perform.
22
Table of Contents
Under certain circumstances, the Trust provides that the Trustee may be required to reconvey to Whiting a portion of the NPI, which may impact how quickly 11.79 MMBOE are produced from the underlying properties for purposes of the NPI.
If Whiting is notified by a person with whom Whiting is a party to a contract containing a prior reversionary interest that Whiting is required to convey any of the underlying properties to such person or cease production from any well, then Whiting may provide such conveyance with respect to such underlying property or permanently cease production from such well. Such a reversionary interest typically results from the provisions of a joint operating agreement that governs the drilling of wells on jointly owned property and financial arrangements for instances where all owners may not want to make the capital expenditure necessary to drill a new well. The reversionary interest is created because an owner that does not consent to capital expenditures will not have to pay its share of the capital expenditure, but instead will relinquish its share of proceeds from the well until the consenting owners receive payout (or a multiple of payout) of their capital expenditures. In such case, Whiting may request the Trustee to reconvey to Whiting the NPI with respect to any such underlying property or well. The Trust will not receive any consideration for such reconveyance of a portion of the NPI. Such reconveyance of a portion of the NPI may extend the time it takes 11.79 MMBOE (10.61 MMBOE at the 90% NPI) to be produced from the underlying properties for purposes of the NPI.
The Trust has not requested a ruling from the IRS regarding the tax treatment of ownership of the Trust units. If the IRS were to determine (and be sustained in that determination) that the Trust is not a “grantor trust” for federal income tax purposes, or that the NPI is not properly treated as a production payment (and thus could fail to qualify as a debt instrument) for federal income tax purposes, the Trust unitholders may receive different and potentially less advantageous tax treatment than they anticipated.
If the Trust were not treated as a grantor trust for federal income tax purposes, the Trust should be treated as a partnership for such purposes. Although the Trust would not become subject to federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the Trust unitholders, the Trust’s tax reporting requirements would be more complex and costly to implement and maintain, and its distributions to unitholders could be reduced as a result.
If the NPI were not treated as a debt instrument, any deductions allowed to an individual Trust unitholder in their recovery of basis in the NPI may be itemized deductions, the deductibility of which would be subject to limitations that may or may not apply depending upon the unitholder’s circumstances.
Neither Whiting nor the Trustee has requested a ruling from the IRS regarding these tax questions, and neither Whiting nor the Trust can assure that such a ruling would be granted if requested or that the IRS will not challenge this position on audit.
Thus, no assurance can be provided that the opinions and statements set forth in the discussion of U.S. federal income tax consequences in the prospectus dated March 22, 2012 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 tax treatment of an investment in Trust units could be affected by recent and potential legislative, judicial or administrative changes and differing opinions, possibly on a retroactive basis.
The U.S. federal income tax treatment of an investment in our Trust may be modified by administrative or legislative changes, or by judicial interpretation, at any time, possibly on a retroactive basis. For example, the Health Care and Education Affordability Reconciliation Act of 2010 includes a provision that, in taxable years beginning after December 31, 2012, subjects an individual having modified adjusted gross income in excess of $200,000 (or $250,000 for married taxpayers filing joint returns) to a “medicare tax” equal generally to 3.8% of the lesser of such excess or the individual’s net investment income, which appears to include interest income derived from investments such as the Trust units as well as any net gain from the disposition of Trust units. In addition, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate for individuals will increase to 39.6%for ordinary income and 20% on long-term capital gains. Moreover, these rates are subject to change by new legislation at any time. Lastly, absent any new legislation affecting the matter, beginning January 1, 2013, itemized deductions that are otherwise allowable will be reduced by the lesser of (i) 3% of adjusted gross income over $100,000 ($50,000 in the case of a separate return by a married individual), as adjusted for inflation and (ii) 80% of the amount of itemized deductions that are otherwise allowable.
23
Table of Contents
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 may not receive cash distributions 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.
The exhibits listed in the accompanying index to exhibits are filed as part of this Quarterly Report on Form 10-Q.
24
Table of Contents
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| WHITING USA TRUST II | ||
| By: | THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A. | |
| By: | /s/ MIKE ULRICH | |
| Mike Ulrich | ||
| Vice President | ||
May 15, 2012
The Registrant, Whiting USA Trust II, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available, and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that such function exists pursuant to the terms of the Trust agreement under which it serves.
25
Table of Contents
Exhibit Number | Description | ||||||
3.1* | — | Certificate of Trust of Whiting USA Trust II [Incorporated herein by reference to Exhibit 3.3 to the Registration Statement on Form S-1 (Registration No. 333-178586)]. | |||||
3.2* | — | Amended and Restated Trust Agreement, dated March 28, 2012, by and among Whiting Oil and Gas Corporation, The Bank of New York Mellon Trust Company, N.A. as Trustee and Wilmington Trust, National Association, as Delaware Trustee [Incorporated herein by reference to Exhibit 3.1 to the Trust’s Current Report on Form 8-K filed on March 28, 2012 (File No. 001-35459)]. | |||||
10.1* | — | Conveyance and Assignment, dated March 28, 2012, from Whiting Oil and Gas Corporation to The Bank of New York Mellon Trust Company, N.A. as Trustee of Whiting USA Trust II [Incorporated herein by reference to Exhibit 10.1 to the Trust’s Current Report on Form 8-K filed on March 28, 2012 (File No. 001-35459)]. | |||||
10.2* | — | Administrative Services Agreement, dated March 28, 2012, by and between Whiting Oil and Gas Corporation and Whiting USA Trust II [Incorporated herein by reference to Exhibit 10.2 to the Trust’s Current Report on Form 8-K filed on March 28, 2012 (File No. 001-35459)]. | |||||
31 | — | Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |||||
32 | — | Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |||||
(* Asterisk indicates exhibit previously filed with the SEC and incorporated herein by reference.)
26