PART I
Item 1.
Business
General
Whiting USA Trust I is a statutory trust formed in October 2007 under the Delaware Statutory Trust Act, pursuant to a
trust agreement (the Trust agreement) among Whiting Oil and Gas as trustor, The Bank of New York Trust Company, N.A., as Trustee (subsequently renamed The Bank of New York Mellon Trust Company, N.A., and hereinafter referred to as
Trustee) and Wilmington Trust Company as Delaware Trustee (the Delaware Trustee). The initial capitalization of the Trust estate was funded by Whiting in November 2007. The Trust maintains its offices at the office of the
Trustee, at 919 Congress Avenue, Austin, Texas 78701. The telephone number of the Trustee is 1-800-852-1422.
The Trust makes
copies of its reports under the Exchange Act available at
http://whx.investorhq.businesswire.com
. The Trusts filings under the Exchange Act are also available electronically from the website maintained by the Securities and Exchange
Commission (SEC) at
http://www.sec.gov
. In addition, the Trust will provide electronic and paper copies of its recent filings free of charge upon request to the Trustee.
As of December 31, 2007, the Trust had no assets other than a de minimus cash balance from its initial capitalization and had
conducted no operations other than organizational activities. In April 2008, the Trust issued 13,863,889 units of beneficial interest in the Trust (Trust units) to Whiting in exchange for the conveyance of a term net profits interest
(NPI) by Whiting Oil and Gas. The NPI represents the right for the Trust to receive 90% of the net proceeds from Whitings interests in certain existing oil, natural gas and natural gas liquid producing properties which we refer to
as the underlying properties. The underlying properties are located in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions. The underlying properties include interests in 3,081 gross (368.0 net) producing oil and gas
wells. Immediately after the conveyance, Whiting completed an initial public offering of Trust units selling 11,677,500 such units. Whiting retained ownership of 2,186,389 Trust units, or 15.8% of the total Trust units issued and outstanding.
The NPI will terminate when 9.11 MMBOE have been produced and sold from the underlying properties (which amount is the
equivalent of 8.20 MMBOE in respect of the Trusts 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. As of December 31, 2012, on a cumulative accrual basis 6.10 MMBOE (74%) of the Trusts total 8.20 MMBOE have been produced and sold and a cumulative 0.02 MMBOE have been divested. Further detail on the reserves is
provided herein under the section titled PropertiesReserves, and such reserve information is based upon a reserve report prepared by independent reserve engineers Cawley, Gillespie & Associates, Inc. for the underlying
properties at December 31, 2012, which we refer to as the reserve report. According to the
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reserve report, the portion of the 9.11 MMBOE (8.20 MMBOE at the 90% NPI) reserve quantities attributable to the NPI not yet produced or sold as divestitures at December 31, 2012 is
projected to be produced from the underlying properties by June 30, 2015, and the reserve report is based on the assumptions included therein. See Risk Factors in Item 1A of this Annual Report on Form 10-K for additional
discussion. Production from the underlying properties for the year ended December 31, 2012 was approximately 63% oil and approximately 37% natural gas.
Net proceeds payable to the Trust depend upon production quantities; sales prices of oil, natural gas and natural gas liquids; costs to develop and produce the oil and gas; and realized cash settlements
from commodity derivative contracts. In calculating net proceeds, Whiting deducts from gross oil and natural gas sales proceeds, all royalties, lease operating expenses (including costs of workovers), production and property taxes, hedge payments
made by Whiting to the hedge contract counterparty, maintenance expenses, postproduction costs (including plugging and abandonment liabilities) and producing overhead. If at any time costs should exceed gross proceeds, neither the Trust nor the
Trust unitholders would be liable for the excess costs. The Trust however, would not receive any net proceeds until future net proceeds exceed the total of those excess costs, plus interest at the prime rate. For more information on the net proceeds
calculation, see Computation of Net Proceeds later in this section.
Whiting entered into certain costless collar
hedge contracts and in turn conveyed to the Trust the rights and obligations to hedge payments under such contracts. All such contracts terminated as of December 31, 2012, and no additional hedges are allowed to be placed on the Trust assets.
The Trust makes quarterly cash distributions of substantially all of its quarterly cash receipts, after the deduction of fees
and expenses for the administration of the Trust, to holders of its Trust units. Because payments to the Trust are generated by depleting assets and the Trust has a finite life due to the production from the underlying properties diminishing over
time, a portion of each distribution represents a return of the original investment in the Trust units.
The Trustee can
authorize the Trust to borrow money to pay Trust administrative or incidental expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee, Whiting or the Delaware Trustee as a lender, provided the
terms of the loan are similar to the terms it would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself and make
other short-term investments with the funds distributed to the Trust.
The Trust was created to acquire and hold the term NPI
for the benefit of the Trust unitholders pursuant to a conveyance to the Trust from Whiting Oil and Gas. The NPI is the only asset of the Trust, other than cash held for Trust expenses. The NPI is passive in nature, and the Trustee has no management
control over and no responsibility relating to the operation of the
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underlying properties. The business and affairs of the Trust are managed by the Trustee, and Whiting and its affiliates have no ability to manage or influence the operations of the Trust. The oil
and gas properties comprising the underlying properties for which Whiting is designated the operator are currently operated by Whiting and its subsidiaries on a contract operator basis. Whiting, as a matter of course, does not make public
projections as to future sales, earnings or other results relating to the underlying properties.
Marketing and Major Customers
Pursuant to the terms of the conveyance creating the NPI, Whiting has the responsibility to market, or cause to be
marketed, the oil, natural gas and natural gas liquid production attributable to the underlying properties. The terms of the conveyance creating the NPI do not permit Whiting to charge any marketing fee, other than fees for marketing paid to
non-affiliates, when determining the net proceeds upon which the NPI is calculated. As a result, the net proceeds to the Trust from the sales of oil, natural gas and natural gas liquid production from the underlying properties are determined based
on the same price that Whiting receives for oil, natural gas and natural gas liquid production attributable to Whitings remaining interest in the underlying properties.
Whiting principally sells its oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to
pipelines, oil is trucked to storage facilities. Whitings marketing of oil and natural gas can be affected by factors beyond its control, the effects of which cannot be accurately predicted. During 2012, sales to Lion Oil Company, Enterprise
South Texas and Plains Marketing LP accounted for 17%, 15% and 11%, respectively, of total oil and natural gas sales from the underlying properties. There is significant competition among purchasers of crude oil and natural gas in the areas of the
underlying properties, and if the underlying properties were to lose one or both of their largest purchasers, several entities could reasonably be expected to purchase crude oil and natural gas produced from the underlying properties without
significant interruption to the sales.
Competition and Markets
The oil and natural gas industry is highly competitive. Whiting competes with major oil and gas companies and independent oil and gas
companies for oil and natural gas, equipment, personnel and markets for the sale of oil and natural gas. Many of these competitors are financially stronger than Whiting, but even financially troubled competitors can affect the market because of
their need to sell oil and natural gas at any price to attempt to maintain cash flow. The Trust is subject to the same competitive conditions as Whiting and other companies in the oil and natural gas industry.
Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy
include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy, as well as business conditions,
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conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas. Future price fluctuations for oil,
natural gas and natural gas liquids will directly impact Trust distributions, estimates of reserves attributable to the Trusts interests and estimated and actual future net revenues to the Trust.
Description of Trust Units
Each Trust unit is a unit of beneficial interest in the Trust and is entitled to receive cash distributions from the Trust on a pro rata basis. Each Trust unitholder has the same rights regarding his or
her Trust units as every other Trust unitholder has regarding his or her units. The Trust units are in book-entry form only and are not represented by certificates.
Periodic Reports
The Trustee files all required Trust federal and state
income tax and information returns. The Trustee prepares and mails to Trust unitholders annual reports that Trust unitholders need to correctly report their share of the Trusts income and deductions. The Trustee also causes to be prepared and
filed reports required under the Securities Exchange Act of 1934, as amended, and by the rules of any securities exchange or quotation system on which the Trust units are listed or admitted to trading, and is responsible for causing the Trust to
comply with all of the provisions of the Sarbanes-Oxley Act, including but not limited to, establishing, evaluating and maintaining a system of internal controls over financial reporting in compliance with the requirements of Section 404
thereof. Each Trust unitholder and his or her representatives may examine, for any proper purpose, during reasonable business hours, the records of the Trust and the Trustee.
Liability of Trust Unitholders
Under the Delaware Statutory Trust Act,
Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts
in jurisdictions outside of Delaware would give effect to such limitation.
Voting Rights of Trust Unitholders
The Trustee or Trust unitholders owning at least 10% of the outstanding Trust units may call meetings of Trust unitholders. The Trust is
responsible for all costs associated with calling a meeting of Trust unitholders, unless such meeting is called by the Trust unitholders in which case the Trust unitholders are responsible for all costs associated with calling such meeting. Meetings
must be held in such location as is designated by the Trustee in the notice of such meeting. The Trustee must send written notice of the time and place of the meeting and the matters to be acted upon to all of the Trust unitholders at least 20 days
and not more than 60 days before the meeting. Trust unitholders representing a majority of Trust units outstanding must be present or represented to have a quorum. Each Trust unitholder is entitled to one vote for each Trust unit owned.
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Unless otherwise required by the Trust agreement, a matter may be approved or disapproved by
the vote of a majority of the Trust units held by the Trust unitholders at a meeting where there is a quorum. This is true even if a majority of the total Trust units did not approve it. In determining whether the holders of the required number of
units have approved any matter that is submitted to a vote of unitholders, those units owned by Whiting will be disregarded if such matter either would result in increased costs and expenses to the Trust or would adversely affect the economic
interests of Trust unitholders. The affirmative vote of the holders of a majority of the outstanding Trust units is required to:
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remove the Trustee or the Delaware Trustee;
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amend the Trust agreement (except with respect to certain matters that do not adversely affect the rights of Trust unitholders in any
material respect);
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merge or consolidate the Trust with or into another entity;
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approve the sale of assets of the Trust unless the sale involves the release of less than or equal to 0.25% of the total production from the
underlying properties for the last twelve months and the aggregate asset sales do not have a fair market value in excess of $500,000 for the last twelve months; or
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agree to amend or terminate the conveyance.
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In addition, certain amendments to the Trust agreement, conveyance, administrative services agreement and registration rights agreement may be made by the Trustee without approval of the Trust
unitholders. The Trustee must consent before all or any part of the Trust assets can be sold, except in connection with the dissolution of the Trust or limited sales directed by Whiting in conjunction with its sale of underlying properties.
Termination of the Trust; Sale of the Net Profits Interest
The NPI will terminate at the time when 9.11 MMBOE (8.20 MMBOE at the 90% NPI) have been produced and sold from the underlying properties, and the Trust will soon thereafter wind up its affairs and
terminate, after which it will pay no further distributions. The Trust will dissolve prior to the termination of the NPI if:
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the Trust sells the NPI;
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annual gross proceeds to the Trust attributable to the NPI are less than $1.0 million for each of any two consecutive years;
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the holders of a majority of the outstanding Trust units vote in favor of dissolution; or
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the Trust is judicially terminated.
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The Trustee would then sell all of the Trusts assets, either by private sale or public
auction, and distribute the net proceeds of the sale to the Trust unitholders.
Computation of Net Proceeds
The provisions of the conveyance governing the computation of net proceeds are detailed and extensive. The following
information summarizes the material information contained in the conveyance related to the computation of net proceeds. For more detailed provisions concerning the NPI, we make reference to the conveyance agreement, which is listed as an exhibit to
this Annual Report on Form 10-K.
Net Profits Interest
The term NPI was conveyed to the Trust by Whiting Oil and Gas in April 2008 by means of a conveyance instrument that has been recorded in the appropriate real property records in each county where the
underlying properties are located. The NPI burdens the interests owned by Whiting in the underlying properties.
The
conveyance creating the NPI provides that the Trust is entitled to receive an amount of cash for each quarter equal to 90% of the net proceeds (calculated as described below) from the sale of oil, natural gas and natural gas liquid production
attributable to the underlying properties.
The amounts paid to the Trust for the NPI are based on the definitions of
gross proceeds and net proceeds contained in the conveyance and described below. Under the conveyance, net proceeds are computed quarterly, and 90% of the aggregate net proceeds attributable to a computation period are paid
to the Trust no later than 60 days following the end of the computation period (or the next succeeding business day). Whiting does not pay to the Trust any interest on the net proceeds held by Whiting prior to payment to the Trust. The Trustee makes
distributions to Trust unitholders quarterly.
Gross proceeds means the aggregate amount received by Whiting from
sales of oil, natural gas and natural gas liquids produced from the underlying properties (other than amounts received for certain future non-consent operations). Gross proceeds does not include any amount for oil, natural gas or natural gas liquids
lost in production or marketing or used by Whiting in drilling, production and plant operations. Gross proceeds includes take-or-pay or ratable take payments for future production in the event that they are not subject to
repayment due to insufficient subsequent production or purchases.
Net proceeds means gross proceeds less Whitings share of
the following:
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all payments to mineral or landowners, such as royalties or other burdens against production, delay rentals, shut-in oil and natural gas
payments, minimum royalty or other payments for drilling or deferring drilling;
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any taxes paid by the owner of an underlying property to the extent not deducted in calculating gross proceeds, including estimated and
accrued general property (ad valorem), production, severance, sales, gathering, excise and other taxes;
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the aggregate amounts paid by Whiting upon settlement of the hedge contracts on a quarterly basis, as specified in the hedge contracts;
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any extraordinary taxes or windfall profits taxes that may be assessed in the future that are based on profits realized or prices received
for production from the underlying properties;
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costs paid by an owner of an oil and natural gas property comprising the underlying properties under any joint operating agreement;
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costs and expenses, costs and liabilities of workovers, operating and producing oil, natural gas and natural gas liquids, including allocated
expenses such as labor, vehicle and travel costs and materials and any plugging and abandonment liabilities other than costs and expenses for certain future non-consent operations;
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costs or charges associated with gathering, treating and processing oil, natural gas and natural gas liquids;
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a producing overhead charge in accordance with existing operating agreements;
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to the extent Whiting is the operator of an underlying property and there is no operating agreement covering such underlying property, the
overhead charges allocated by Whiting to such underlying property calculated in the same manner Whiting allocates overhead to other similarly owned property;
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costs for recording the conveyance and costs estimated to record the termination and/or release of the conveyance;
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costs paid to the counterparty under the hedge contracts or to the persons that provide credit to maintain any hedge contracts, excluding any
hedge settlement amounts;
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amounts previously included in gross proceeds but subsequently paid as a refund, interest or penalty; and
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costs and expenses for renewals or extensions of leases.
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All of the hedge payments received by Whiting from the counterparty upon settlements of hedge contracts and certain other non-production
revenues, as detailed in the conveyance, will offset the operating expenses outlined above in calculating the net proceeds. If the hedge payments received by Whiting and certain other non-production revenues exceed the operating
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expenses during a quarterly period, the ability to use such excess amounts to offset operating expenses may be deferred, with interest accruing on such amounts at the prevailing money market
rate, until the next quarterly period when such amounts are less than such expenses. If any excess amounts have not been used to offset costs at the time when 9.11 MMBOE (8.20 MMBOE at the 90% NPI) have been produced and sold from the underlying
properties, which is the time when the NPI will terminate, then unitholders will not be entitled to receive the benefit of such excess amounts.
Although capital expenditures for the testing, drilling, completion, equipping, plugging back or recompletion of any well that is a part of the underlying properties cannot be deducted from gross proceeds
pursuant to the terms of the conveyance agreement, Whiting incurred capital expenditures of $6.8 million on the underlying properties in 2012. Such expenditures were not deducted from gross proceeds or Trust distributions in 2012, but they may have
the effect of ultimately accelerating the receipt of NPI net proceeds and thereby benefiting Trust unitholders by accelerating their return on investment. The Trust cannot provide any assurance that this will continue to occur or that future capital
expenditures will be consistent with historical levels.
Pursuant to the terms of the applicable joint operating agreements,
Whiting deducts from the gross proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally, for those underlying properties for which Whiting is the operator but 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, as is customary in the oil and gas industry. Operating
overhead activities include various engineering, legal and administrative functions. The Trusts portion of the monthly charge averaged $419 per month per active operated well, which totaled $1.7 million for the four distributions made during
the year ended December 31, 2012. The fee is adjusted annually pursuant to COPAS guidelines and will increase or decrease each year based on changes in the year-end index of average weekly earnings of crude petroleum and natural gas workers.
In the event that the net proceeds for any computation period is a negative amount, the Trust will receive no payment for
that period, and any such negative amount plus accrued interest at the prevailing money market rate will be deducted from gross proceeds in the following computation period for purposes of determining the net proceeds for that following computation
period.
Gross proceeds and net proceeds are calculated on a cash basis, except that certain costs, primarily ad valorem taxes
and expenditures of a material amount, may be determined on an accrual basis.
Commodity Hedge Contracts
Whiting entered into certain costless collar hedge contracts, and Whiting in turn conveyed to the Trust the rights and obligations to
hedge payments Whiting made or received under such
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costless collar hedge contracts. These contracts were entered into to reduce the exposure to volatility in the underlying properties oil and gas revenues due to fluctuations in crude oil
and natural gas prices, and to achieve more predictable cash flows. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general
economic conditions. Costless collars are designed to establish floor and ceiling prices on anticipated oil and gas production. The hedge contracts were placed with a single trading counterparty, JPMorgan Chase Bank National Association and were in
place during the 2012, 2011 and 2010 periods presented in this Annual Report on Form 10-K. However, all hedging contracts terminated as of December 31, 2012. No additional hedges are allowed to be placed on Trust assets, nor can the Trust enter
into derivative contracts for trading or speculative purposes.
Crude oil costless collar arrangements settle based on the
average of the closing settlement price for each commodity business day in the contract period. Natural gas costless collar arrangements settle based on the closing settlement price on the second to last scheduled trading day of the month prior to
delivery. In a collar arrangement, the counterparty is required to make a payment to Whiting for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. Whiting is required to
make a payment to the counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price.
The amount received by Whiting from the hedge contract counterparty upon settlements of the hedge contracts reduces the operating expenses related to the underlying properties in calculating net proceeds.
In addition, the aggregate amount paid by Whiting on settlement of the hedge contracts reduces the amount of net proceeds paid to the Trust.
Additional Provisions
If a controversy
arises as to the sales price of any production, then for purposes of determining gross proceeds:
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Amounts withheld or placed in escrow by a purchaser are not considered to be received by Whiting until actually collected;
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amounts received by Whiting and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until
disbursed to Whiting by the escrow agent; and
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amounts received by Whiting and not deposited with an escrow agent will be considered to have been received.
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The Trustee is not obligated to return any cash received from the NPI. Any overpayments made to the Trust by Whiting due to adjustments
to prior calculations of net proceeds or otherwise
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will reduce future amounts payable to the Trust until Whiting recovers the overpayments plus interest at the prevailing money market rate. Whiting may make such adjustments to prior calculations
of net proceeds without the consent of the Trust unitholders or the Trustee but is required to provide the Trustee with notice of such adjustments and supporting data.
As the designated operator of a property comprising the underlying properties, Whiting may enter into farm-out, operating, participation and other similar agreements to develop the property. Whiting may
enter into any of these agreements without the consent or approval of the Trustee or any Trust unitholder.
Whiting has the
right to abandon any well or property if it reasonably believes the well or property ceases to produce or is not capable of producing in commercially paying quantities. In making such decisions, Whiting is required under the applicable conveyance to
operate the underlying properties as a reasonably prudent operator in the same manner it would if these properties were not burdened by the NPI. Upon termination of the lease, the portion of the NPI relating to the abandoned property will be
extinguished.
Whiting must maintain books and records sufficient to determine the amounts payable under the NPI to the Trust.
Quarterly and annually, Whiting must deliver to the Trustee a statement of the computation of net proceeds for each computation period. The Trustee has the right to inspect and copy the books and records maintained by Whiting during normal business
hours and upon reasonable notice.
Federal Income Tax Matters
The following is a summary of certain U.S. federal income tax matters that may be relevant to the Trust unitholders. This summary is
based upon current provisions of the Internal Revenue Code of 1986, as amended, which we refer to as the Code, existing and proposed Treasury regulations thereunder and current administrative rulings and court decisions, all of which are
subject to changes that may or may not be retroactively applied. No attempt has been made in the following summary to comment on all U.S. federal income tax matters affecting the Trust or the Trust unitholders.
The summary is limited to Trust unitholders who are individual citizens or residents of the United States. Accordingly, the following
summary has limited application to domestic corporations and persons subject to specialized federal income tax treatment such as, without limitation, tax-exempt organizations, regulated investment companies, insurance companies, and foreign persons
or entities.
Each Trust unitholder should consult his own tax advisor with respect to his particular circumstances.
Classification
and Taxation of the Trust
Tax counsel to the Trust advised the Trust at the time of formation that, for U.S. federal
income tax purposes, in its opinion the Trust would be treated as a grantor trust and not as an
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unincorporated business entity. No ruling has been or will be requested from the Internal Revenue Service, which we refer to as the IRS or another taxing authority. The remainder of
the discussion below is based on tax counsels opinion, at the time of formation, that the Trust will be classified as a grantor trust for U.S. federal income tax purposes. As a grantor trust, the Trust is not subject to U.S. federal income tax
at the Trust level. Rather, each Trust unitholder is considered for federal income tax purposes to own its proportionate share of the Trusts assets directly as though no Trust were in existence. The income of the Trust is deemed to be received
or accrued by the Trust unitholder at the time such income is received or accrued by the Trust, rather than when distributed by the Trust. Each Trust unitholder is subject to tax on its proportionate share of the income and gain attributable to the
assets of the Trust and is entitled to claim its proportionate share of the deductions and expenses attributable to the assets of the Trust, subject to applicable limitations, in accordance with the Trust unitholders tax method of accounting
and taxable year without regard to the taxable year or accounting method employed by the Trust.
On the basis of that advice,
the Trust will file annual information returns, reporting to the Trust unitholders all items of income, gain, loss, deduction and credit. The Trust will allocate items of income, gain, loss, deductions and credits to Trust unitholders based on
record ownership at each quarterly record date. It is possible that the IRS or another tax authority could disagree with this allocation method and could assert that income and deductions of the Trust should be determined and allocated on a daily,
prorated or other basis, which could require adjustments to the tax returns of the Trust unitholders affected by the issue and result in an increase in the administrative expense of the Trust in subsequent periods.
Classification of the Net Profits Interest
Tax counsel to the Trust also advised the Trust at the time of formation that, for U.S. federal income tax purposes, based upon representations made by Whiting regarding the expected economic life of the
underlying properties and the expected duration of the NPI, in its opinion the NPI should be treated as a production payment under Section 636 of the Code, or otherwise as a debt instrument. On the basis of that advice, the Trust
treats the NPI as indebtedness subject to Treasury regulations applicable to contingent payment debt instruments, and by purchasing Trust units, a Trust unitholder agrees to be bound by the Trusts application of those regulations, including
the Trusts determination of the rate at which interest will be deemed to accrue on the NPI. No assurance can be given that the IRS or another tax authority will not assert that the NPI should be treated differently. Any such different
treatment could affect the timing and character of income, gain or loss in respect of an investment in Trust units and could require a Trust unitholder to accrue income at a rate different than that determined by the Trust.
Reporting Requirements for Widely-Held Fixed Investment Trusts
Some Trust units are held by middlemen, as such term is broadly defined in the Treasury regulations (and includes custodians, nominees, certain joint owners and brokers holding an
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interest for a custodian street name, collectively referred to herein as middlemen). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust
(WHFIT) for U.S. federal income tax purposes. The Bank of New York Mellon Trust Company, N.A., 919 Congress Avenue, Austin, Texas 78701, telephone number 1-800-852-1422, is the representative of the Trust that will provide the tax
information in accordance with applicable Treasury regulations governing the information reporting requirements of the Trust as a WHFIT. Notwithstanding the foregoing, the middlemen holding Trust units on behalf of unitholders, and not the Trustee
of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury regulations with respect to such Trust units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders
whose Trust units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust units. Any generic tax information provided by the Trustee of the Trust is
intended to be used only to assist Trust unitholders in the preparation of their federal and state income tax returns.
Available Trust Tax
Information
In compliance with the Treasury regulations reporting requirements for non-mortgage widely-held fixed
investment trusts and the dissemination of Trust tax reporting information, the Trustee provides a generic tax information reporting booklet which is intended to be used only to assist Trust unitholders in the preparation of their 2012 federal and
state income tax returns. The projected payment schedule for the NPI is included with the tax information booklet. This tax information booklet can be obtained at
http://whx.investorhq.businesswire.com
.
Environmental Matters and Regulation
The operations of the underlying properties are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into
the environment. These laws and regulations may, among other things:
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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and
natural gas drilling and production activities;
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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;
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require investigatory or remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and
plug abandoned wells; and
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enjoin some or all of the operations of the underlying properties deemed in non-compliance with permits issued pursuant to such environmental
laws and regulations.
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Failure to comply with these laws and regulations may trigger a variety of administrative,
civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations or imposing additional compliance requirements on such
operations. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, these laws, rules and regulations
may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects
profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and
natural gas industry could have a significant impact on the operating costs of the properties comprising the underlying properties.
The following is a summary of the more significant existing laws, rules and regulations to which the operations of the underlying properties are subject that are material to the operation of the
underlying properties.
Waste Handling.
The Resource Conservation and Recovery Act, as amended (RCRA), and
comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency (EPA) the individual
states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. In its operations at the underlying properties, Whiting generates solid and hazardous wastes that are subject to RCRA and
comparable state laws. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRAs non-hazardous waste provisions.
However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. In September 2010, the Natural Resources Defense Council filed a
petition with the EPA, requesting them to reconsider the RCRA exemption for exploration, production and development wastes but, to date, the agency has not taken any action on the petition. The EPA has not formally responded to this petition yet.
Any such change in the current RCRA exemption and comparable state laws, could result in an increase in the costs to manage and dispose of wastes, which could have a material adverse effect on the cash distributions to the Trust unitholders.
Comprehensive Environmental Response, Compensation and Liability Act
. The Comprehensive Environmental Response,
Compensation and Liability Act of 1980, as amended (CERCLA), also known as the Superfund law, and comparable state laws impose strict joint and several liability, without regard to fault or the legality of conduct, on classes of persons
who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of the
hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up
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the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. While Whiting generates materials in the
course of its operations of the underlying properties that may be regulated as hazardous substances, Whiting has not been notified that it has been named as a potentially responsible party at or with respect to any Superfund sites. In addition, it
is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
The underlying properties of the Trust may have been used for oil and natural gas exploration and production for many years. Although
Whiting believes that it has utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties, or on or under other
locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, the underlying properties of the Trust may have been operated by third parties or by previous owners or operators whose treatment
and disposal of hazardous substances, wastes or hydrocarbons was not under Whitings control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, Whiting
could be required to remove previously disposed substances and wastes, remediate contaminated property, perform remedial plugging or pit closure operations to prevent future contamination or to pay some or all of the costs of any such action.
Water Discharges.
The Federal Water Pollution Control Act, or the Clean Water Act, as amended (the CWA),
and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into state waters or waters of the United States. The discharge of pollutants into
regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and
similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits
for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and
analogous state laws and regulations.
Hydraulic Fracturing.
Hydraulic fracturing is an important and common practice
that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. Hydraulic fracturing has been utilized during the completion of wells drilled on the underlying properties, and Whiting expects it will also be
used in the future. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions.
However, the EPA recently took the position that hydraulic fracturing
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operations using diesel are subject to regulation under the Underground Injection Control program of the Safe Drinking Water Act as Class II wells 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 EPAs recent decision. At the same time, the EPA has commenced a
study of the potential environmental impacts of hydraulic fracturing activities on drinking water resources. The EPA published a progress report of the study in December 2012 and expects to release the final results by 2014. Moreover, the EPA
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, 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 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 hydraulic fracturing are adopted, such legal requirements could make it more difficult or costly for Whiting to
perform hydraulic fracturing activities on the underlying properties and thereby could affect the determination of whether a well is commercially viable. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural
gas that Whiting is ultimately able to produce in commercially paying quantities from the underlying properties and could reduce cash distributions by the Trust and the value of Trust units.
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Global Warming and Climate Control.
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 earths atmosphere and other climate changes. Based on these findings, the EPA has begun adopting and implementing regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, as amended (the
CAA), including one rule that limits emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger the CAA construction and operating permit
requirements for stationary sources, commencing when the motor vehicle standards took effect 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 GHGs, 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. Whiting believes that it is in compliance with all substantial applicable emissions
requirements, and it is preparing to comply with future requirements.
In addition, both houses of Congress have considered
legislation to reduce emissions of GHGs, and many states have already taken legal measures to reduce emissions of GHGs, primarily through the development of GHG inventories, 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 GHGs associated with the operations of the underlying properties which will require Whiting to incur costs to
inventory and reduce emissions of GHGs associated with the operations of the underlying properties and which 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 GHGs in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events.
Air Emissions.
The CAA and comparable state laws, regulate emissions of various air pollutants from various industrial sources
through air emissions permitting programs and also impose other monitoring and reporting requirements. Operators of the underlying properties, including Whiting, may be required to incur certain capital expenditures in the future for air
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pollution control equipment in connection with obtaining and maintaining pre-construction and operating permits and approvals for air emissions. In addition, the EPA has developed, and continues
to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. For example, on April 17, 2012, the EPA finalized rules that would establish new air emission controls for oil and natural gas production
operations. Specifically, the EPAs rule includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently
associated with oil and natural gas production and processing activities. Among other things, these standards would require the application of reduced emission completion techniques for completion of newly drilled and fractured wells in addition to
existing wells that are refractured. The rules also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. These rules could require a number of modifications to operations at
the underlying properties including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact cash distributions to
unitholders. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.
OSHA and Other Laws and Regulation.
Whiting is subject to the requirements of the federal Occupational Safety and Health Act, as
amended (OSHA), and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that Whiting organize and/or disclose
information about hazardous materials used or produced in its operations. Whiting believes that it is in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.
Endangered Species Considerations.
The federal Endangered Species Act, as amended (ESA), restricts activities that may
affect endangered and threatened species or their habitats. If endangered species are located in areas of the underlying properties where Whiting or the other underlying property operators wish to conduct seismic surveys, development activities or
abandonment operations, the work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish
and Wildlife Service is required to consider listing more than 250 species as endangered under the ESA. Under the September 9, 2011 settlement, the federal agency is required to begin issuing decisions with respect to the 250 candidate species
by the end of 2011 and no later than the end of the 2013 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause operators of those underlying
properties, including Whiting, to incur increased costs arising from species protection measures or could result in limitations on their exploration and production activities that could have an adverse impact on their ability to develop and produce
reserves.
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Consideration of Environmental Issues in Connection with Governmental Approvals.
Whitings operations frequently require licenses, permits and/or other governmental approvals. Several federal statutes, including the Outer Continental Shelf Lands Act (OCSLA), the National Environmental Policy Act
(NEPA) and the Coastal Zone Management Act (CZMA) require federal agencies to evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions. OCSLA, for instance, requires
the U.S. Department of Interior to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or human environment. Similarly, NEPA requires the Department of Interior and other federal agencies to
evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency would have to prepare an environmental assessment and, potentially, an environmental impact statement. CZMA, on
the other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands associated with various uses, including offshore oil and gas development. In obtaining various approvals from the
Department of Interior, Whiting must certify that it will conduct its activities in a manner consistent with all applicable regulations.
Whiting believes that it is in compliance in all material respects with all existing environmental laws and regulations applicable to the current operations of the underlying properties and that its
continued compliance with existing requirements will not have a material adverse effect on the cash distributions to the Trust unitholders. For instance, Whiting did not incur any material capital expenditures for remediation or pollution control
activities for the year ended December 31, 2012 with respect to these properties. Additionally, Whiting has informed the Trust that Whiting is not aware of any environmental issues or claims that will require material capital expenditures
during 2013 with respect to these properties. However, there is no assurance that the passage of more stringent laws or implementing regulations in the future will not have a negative impact on the operations of these properties and the cash
distributions to the Trust unitholders.
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Item 1A.
Risk Factors
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.
The amounts of cash distributions by
the Trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquid prices.
The
reserves attributable to the underlying properties and the quarterly cash distributions of the Trust are highly dependent upon the prices realized from the sale of oil, natural gas and natural gas liquids. Prices of oil, natural gas and natural gas
liquids 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:
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changes in regional, domestic and global supply and demand for oil and natural gas;
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the actions of the Organization of Petroleum Exporting Countries;
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the price and quantity of imports of foreign oil and natural gas;
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political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity, such as recent
conflicts in the Middle East;
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the level of global oil and natural gas exploration and production activity;
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the effects of global credit, financial and economic issues;
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the level of global oil and natural gas inventories;
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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;
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technological advances affecting energy consumption;
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domestic and foreign governmental regulations;
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proximity and capacity of oil and natural gas pipelines and other transportation facilities;
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the price and availability of competitors supplies of oil and gas in captive market areas;
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the price and availability of alternative fuels; and
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Moreover, government regulations, such as regulation of oil and natural gas gathering and transportation, can adversely affect commodity prices in the long term.
Lower prices of oil, natural gas and natural gas liquids will reduce the amount of the net proceeds to which the Trust is entitled and
may ultimately reduce the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties. As a result, the operator of any of the underlying properties could determine during periods of low commodity
prices to shut in or curtail production from the underlying properties. In addition, the operator of these properties could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to
continue to produce for a longer period under conditions of higher prices. Because these properties are mature, decreases in commodity prices could have a more significant effect on the economic viability of these properties as compared to more
recently discovered properties. The commodity price sensitivity of these mature wells is due to a culmination of factors that vary from well to well, including the additional costs associated with water handling and disposal, chemicals, surface
equipment maintenance, downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result, the volatility of commodity prices may cause the amount of future cash distributions to Trust
unitholders to fluctuate, and a substantial decline in the price of oil, natural gas or natural gas liquids will likely materially reduce the amount of cash available for distribution to the Trust unitholders.
Whiting entered into certain costless collar hedge contracts, which were conveyed to the Trust to reduce the exposure to volatility in
the underlying properties oil and gas revenues due to fluctuations in crude oil and natural gas prices, and to achieve more predictable cash flows. However, all such costless collar hedge contracts terminated as of December 31, 2012, and
no additional hedges are allowed to be placed on the Trust assets. The amount of the cash settlement gains received on commodity derivatives attributable to the costless collar hedge contracts for the years ended December 31, 2012, 2011 and
2010 totaled $5.9 million, $4.5 million and $4.3 million, respectively. Assuming prior period crude oil and natural gas prices and production are similar to future periods, the termination of the costless collar hedge contracts as of the end of 2012
would result in reduced future cash distributions to unitholders due to no cash settlement gains on derivatives to be received in future periods.
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The reserves attributable to the underlying properties are depleting assets and
production from those reserves will diminish over time. Furthermore, the Trust is precluded from acquiring other oil and natural gas properties or NPI to replace the depleting assets and production.
The net proceeds payable to the Trust from the NPI are derived from the sale of oil, natural gas and natural gas liquids produced from
the underlying properties. The reserves attributable to the underlying properties are depleting assets, which means that 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, 2012 represents an aggregate depletion percentage of 94.2% 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. Total oil and natural gas production attributable to the underlying properties declined 5.9% from 2008 to 2009, 11.8% from 2009 to 2010 and 8.8% from 2010 to 2011, and
remained consistent from 2011 to 2012. Also based on the 2012 reserve report, overall production for both oil and gas attributable to the underlying properties is expected to decline at rates ranging from 9% to 11% annually from 2013 through the
estimated June 30, 2015 NPI termination date. 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 when 9.11 MMBOE (8.20 MMBOE at the 90% NPI) have been produced and sold from the underlying properties, which is projected by the reserve report to occur by June 30, 2015. As
of December 31, 2012, on a cumulative accrual basis 6.10 MMBOE of the Trusts total 8.20 MMBOE have been produced and sold and a cumulative reserve quantity of 0.02 MMBOE have been divested. Furthermore, the Trust agreement provides that
the Trusts business activities are limited to owning the NPI and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyance related to the NPI. As a result, the Trust is not
permitted to acquire other oil and natural gas properties or NPI to replace the depleting assets and production attributable to the NPI.
Future maintenance projects on the underlying properties beyond those which are currently estimated may affect the quantity of proved reserves that can be economically produced from the underlying
properties. The timing and size of these projects will depend on, among other factors, the market prices of oil, natural gas and natural gas liquids. If operators of the underlying properties do not implement required maintenance projects when
warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by Whiting or estimated in the reserve report. In addition, Whiting is not required to make any capital expenditures.
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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.
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:
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historical production from the area compared with production rates from other producing areas;
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the assumed effect of governmental regulation; and
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assumptions about future prices of oil, natural gas and natural gas liquids, including differentials, production and development costs, gathering
and transportation costs, severance and excise taxes and capital expenditures.
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Changes in these assumptions
may materially alter production and reserve estimates. The estimated proved reserves attributable to the NPI and the estimated future net revenues attributable to the NPI are based on estimates of reserve quantities and revenues for the underlying
properties. The quantities of reserves attributable to the underlying properties and the NPI may decrease in the future as a result of future decreases in the price of oil, natural gas or natural gas liquids.
Risks associated with the production, gathering, transportation and sale of oil, natural gas and natural gas liquids could
adversely affect cash distributions by the Trust and the value of the Trust units.
The revenues of the Trust, the
value of the Trust units and the amount of cash distributions to the Trust unitholders will depend upon, among other things, oil, natural gas and natural gas liquid production and prices and the costs incurred to exploit oil and natural gas reserves
attributable to the underlying properties. Drilling, production or transportation accidents that temporarily or permanently halt the production and sale of oil, natural gas and natural gas liquids at any of the underlying properties will reduce
Trust distributions by reducing the amount of net proceeds available for distribution. For example, accidents may occur that result
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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, 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 Trust and the Trust unitholders have
no voting or managerial rights with respect to the underlying properties. As a result, neither the Trust nor the unitholders have any ability to influence the operation of the underlying properties.
Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners of oil and
natural gas properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator
is typically responsible for making decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. Neither the Trustee nor the Trust unitholders have any contractual
ability to influence or control the field operations of, and sale of oil and natural gas from, the underlying properties, including underlying properties where Whiting is the operator. Also, the Trust unitholders have no voting rights with respect
to the operators of these properties and, therefore, have no managerial, contractual or other ability to influence the activities of the operators of these properties.
Whiting has limited control over activities on the underlying properties that Whiting does not operate, which could reduce production from the underlying properties and cash available for
distribution to Trust unitholders.
Whiting is currently designated as the operator of approximately 65% of the
underlying properties based on the December 31, 2012 standardized measure of discounted future net cash flows. However, for the 35% of the underlying properties that it does not operate, Whiting does not have control over normal operating
procedures or expenditures relating to such properties.
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The failure of an operator to adequately perform operations or an operators 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 Whitings control, including the operators decisions with
respect to 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
operators expertise and financial resources and the operators relative interest in the underlying field. Operators may also opt to decrease operational activities following a significant decline in oil or natural gas prices. Because
Whiting does not have a majority interest in most of the non-operated properties comprising the underlying properties, Whiting may not be in a position to remove the operator in the event of poor performance. Accordingly, while Whiting has agreed to
use commercially reasonable efforts to cause the operator to act as a reasonably prudent operator, it will be limited in its ability to do so.
Shortages or increases in costs of oil field equipment, services and qualified personnel 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. Shortages of field personnel and equipment or price increases could significantly decrease the amount of cash available for distribution to the
Trust unitholders, or restrict operations on the underlying properties.
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.
Whiting is not required to make capital expenditures on the underlying properties at historical levels or at all. If Whiting does
not make capital expenditures, then the timing of production from the underlying properties may not be accelerated.
Whiting has made capital expenditures on the underlying properties, which has increased production from the underlying properties.
However, Whiting has no contractual obligation to
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make capital expenditures on the underlying properties in the future. Furthermore, for properties on which Whiting is not designated as the operator, the decision whether to make capital
expenditures is made by the operator and Whiting has no control over the timing or amount of those capital expenditures. Whiting also has the right to non-consent and not participate in the capital expenditures on these properties, in which case
Whiting and the Trust will not receive the production resulting from such capital expenditures. Accordingly, it is likely that capital expenditures with respect to the underlying properties will vary from and may be less than historical levels.
The amount of cash available for distribution by the Trust is reduced by the amount of any royalties, lease operating
expenses, production and property taxes, maintenance expenses, post-production costs and producing overhead.
Production costs on the underlying properties are deducted in the calculation of the Trusts share of net proceeds. In addition,
production and property taxes and any costs or payments associated with post-production costs are deducted in the calculation of the Trusts share of net proceeds. Accordingly, higher or lower production expenses, taxes and post-production
costs directly decrease or increase the amount received by the Trust in respect of its NPI.
If production costs of the
underlying properties exceed the proceeds of production, the Trust will not receive net proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest during the deficit period. If the 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.
An increase in the differential or decrease in the premium between the NYMEX or other benchmark prices of oil and natural gas and
the wellhead price received could reduce cash distributions by the Trust and the value of Trust units.
Oil and
natural gas production from the underlying properties generally trades at a discount, but sometimes at a premium, to the relevant benchmark prices, such as NYMEX. A negative difference between the benchmark price and the price received is called a
differential and a positive difference is called a premium. The differential and premium may vary significantly due to market conditions, the quality and location of production and other risk factors. Whiting cannot accurately predict oil and
natural gas differentials and premiums. Increases in the differential and decreases in the premium between the benchmark price for oil and natural gas and the wellhead price received could reduce cash distributions by the Trust and the value of the
Trust units.
Financial returns to purchasers of Trust units will vary in part based on how quickly 9.11 MMBOE are
produced from the underlying properties and sold, and it is not known when that will occur.
The NPI will terminate
when 9.11 MMBOE have been produced and sold from the underlying properties (which amount is the equivalent of 8.20 MMBOE in respect of the Trusts right to
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receive 90% of the net proceeds from such reserves pursuant to the NPI). The reserve report prepared by the Trusts independent petroleum engineer dated as of December 31, 2012 (the
reserve report) projects that 9.11 MMBOE will have been produced and sold from the underlying properties by June 30, 2015. However, the exact rate of production cannot be predicted with certainty and such amount may be produced
before or after the date projected by the reserve report. If production attributable to the underlying properties is slower than estimated, then financial returns to Trust unitholders will be lower (assuming constant prices) because cash
distributions attributable to such production will occur at a later date.
Under certain circumstances, the Trust
provides that the Trustee may be required to sell the NPI and dissolve the Trust prior to the expected termination of the Trust. As a result, Trust unitholders may not recover their investment.
The Trustee must sell the NPI if the holders of a majority of the Trust units approve the sale or vote to dissolve the Trust. The Trustee
must also sell the NPI if the annual gross proceeds attributable to the NPI are less than $1.0 million for each of any two consecutive years. The sale of the NPI will result in the dissolution of the Trust. The net proceeds of any such sale will be
distributed to the Trust unitholders.
The NPI will terminate when 9.11 MMBOE (8.20 MMBOE at the 90% NPI) have been produced
and sold from the underlying properties. The Trust unitholders will not be entitled to receive any net proceeds from the sale of production from the underlying properties following the termination of the NPI. Therefore, the market price of the Trust
units will likely diminish towards the end of the term of the NPI because the cash distributions from the Trust will cease at the termination of such NPI, and the Trust will have no right to any additional production from the underlying properties
after the term of the NPI.
Conflicts of interest could arise between Whiting and the Trust unitholders.
The interests of Whiting and the interests of the Trust and the Trust unitholders with respect to the underlying
properties could at times differ. For example:
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Whiting has broad discretion over the timing and amount of operating expenditures and activities, including workover expenses and activities, which
could result in higher costs being attributed to the NPI.
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Whiting has the right, subject to significant limitations as described herein, to cause the Trust to release a portion of the NPI in connection with
a sale of a portion of the oil and natural gas properties comprising the underlying properties to which 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.
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The Trust has no employees and is reliant on Whitings employees to operate those underlying properties for which Whiting is designated as the
operator. Whitings employees are also responsible for the operation of other oil and gas properties Whiting owns, which may require a significant portion or all of their time and resources.
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35
The documents governing the Trust generally do not provide a mechanism for resolving these conflicting
interests.
The Trust is managed by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.
The business and affairs of the Trust are managed by the Trustee. The voting rights of a Trust unitholder are more
limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The Trust agreement provides that the
Trustee may only be removed and replaced by a vote of the holders of a majority of the outstanding Trust units at a special meeting of Trust unitholders called by either the Trustee or the holders of not less than 10% of the outstanding Trust units.
Whiting owns approximately 15.8% of the outstanding Trust units. As a result, it may be difficult to remove or replace the Trustee without the approval of Whiting.
Trust unitholders have limited ability to enforce provisions of the NPI.
The Trust agreement permits the Trustee to sue Whiting on behalf of the Trust to enforce the terms of the conveyance creating the NPI. If the Trustee does not take appropriate action to enforce provisions
of the conveyance, the recourse of a Trust unitholder likely would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The Trust agreement expressly limits the Trust unitholders ability to
directly sue Whiting or any other third party other than the Trustee. As a result, the unitholders will not be able to sue Whiting to enforce these rights.
Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.
Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to
stockholders of private corporations under the General Corporation Law of the State of Delaware. Courts in jurisdictions outside of Delaware, however, may not give effect to such limitation.
The operations of the underlying properties may result in significant costs and liabilities with respect to environmental and
operational safety matters, which could reduce the amount of cash available for distribution to Trust unitholders.
Significant costs and liabilities can be incurred as a result of environmental and safety requirements applicable to the oil and natural
gas exploration, development and production activities of the underlying properties. These costs and liabilities could arise under a wide range of federal, regional, state and local environmental and safety laws, regulations, and enforcement
policies, which legal requirements have tended to become increasingly strict over
36
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 Whitings 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 indirectly 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.
37
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 earths 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 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 which could adversely affect
38
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, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on the Trusts assets and the amount of
cash available for distribution to 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 Whitings 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 Acts 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 EPAs recent
decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities on drinking water resources. The EPA published a progress report of the study in December 2012 and expects to release
the final results by 2014. Moreover, the EPA 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
39
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.
The Trusts NPI may be characterized as an executory contract in bankruptcy, which could be rejected
in bankruptcy, thus relieving Whiting from its obligations to make payments to the Trust with respect to the NPI.
Whiting has recorded the conveyance of the NPI in the states where the underlying properties are located in the real property records in
each county where these properties are located. The NPI is a non-operating, non-possessory interest carved out of the oil and natural gas leasehold estate, but certain states have not directly determined whether an NPI is a real or a personal
property interest. Whiting believes that the delivery and recording of the conveyance should create a fully conveyed and vested property interest under the applicable states 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 65% of the underlying properties based on the December 31, 2012 standardized
measure of discounted future net cash flows. The conveyance provides that Whiting will be obligated to market, or cause to be marketed, the production related to underlying properties for which it operates.
Whitings ability to perform its obligations related to the operation of the underlying properties and its obligations to the Trust
will depend on Whitings future financial condition and
40
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 Whitings future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
The disposal by Whiting of its remaining Trust units may reduce the market price of the Trust units.
Whiting owns 15.8% of the Trust units. If Whiting sells these units, then the market price of the Trust units may be reduced. Whiting and the Trust have entered into a registration rights agreement
pursuant to which the Trust has agreed to file a registration statement or shelf registration statement to register the resale of the remaining Trust units held by Whiting and any transferee of the Trust units upon request by such holders.
Under certain circumstances, the Trust provides that the Trustee may be required to reconvey to Whiting a portion of
the NPI, which may impact how quickly 9.11 MMBOE are produced from the underlying properties for purposes of the NPI.
If Whiting is notified by a person with whom Whiting is a party to a contract containing a prior reversionary interest that Whiting is
required to convey any of the underlying properties to such person or cease production from any well, then Whiting may provide such conveyance with respect to such underlying property or permanently cease production from such well. Such a
reversionary interest typically results from the provisions of a joint operating agreement that governs the drilling of wells on jointly owned property and financial arrangements for instances where all owners may not want to make the capital
expenditure necessary to drill a new well. The reversionary interest is created because an owner that does not consent to capital expenditures will not have to pay its share of the capital expenditure, but instead will relinquish its share of
proceeds from the well until the consenting owners receive payout (or a multiple of payout) of their capital expenditures. In such case, Whiting may request the Trustee to reconvey to Whiting the NPI with respect to any such underlying property or
well. The Trust will not receive any consideration for such reconveyance of a portion of the NPI. Such reconveyance of a portion of the NPI may extend the time it takes for 9.11 MMBOE (8.20 MMBOE at the 90% NPI) to be produced from the underlying
properties for purposes of the NPI.
The Trust has not requested a ruling from the IRS regarding the tax treatment of
ownership of the Trust units. If the IRS were to determine (and be sustained in that determination) that the Trust is not a grantor trust for federal income tax purposes, or that the NPI is not properly treated as a production payment
(and thus could fail to qualify as a debt instrument) for federal income tax purposes, the Trust unitholders may receive different and less advantageous tax treatment than they anticipated.
41
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 Trusts 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 unitholders circumstances.
Neither Whiting nor the Trustee has requested a ruling from the IRS regarding these tax questions, and neither Whiting nor the Trust can assure that such a ruling would be granted if requested or that the
IRS will not challenge this position on audit.
Thus, no assurance can be provided that the opinions and statements set forth
in the discussion of U.S. federal income tax consequences would be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the Trust units and the prices at which Trust
units trade. In addition, the costs of any contest with the IRS (whether or not such challenge is successful), principally legal, accounting and related fees, will result in a reduction in cash available for distribution to the Trust unitholders,
and thus will be borne indirectly by the Trust unitholders.
Trust unitholders should be aware of the possible state tax
implications of owning Trust units, and should consult their own tax advisors for advice regarding the state as well as federal tax implications of owning Trust units.
The 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 the 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
individuals 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, beginning January 1, 2013, the highest
marginal U.S. federal income tax rate for individuals increased 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.
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Trust unitholders will be required to pay taxes on their share of the Trusts
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 Trusts taxable asset (which for tax purposes, is a loan receivable owed to the Trust from Whiting) and they receive the Trusts 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 Trusts taxable income or even equal to the actual tax liability that results from that income. Because the Trust typically generates
taxable income that is different in amount than the cash the Trust distributes, the Trust unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of the Trusts taxable income
even if they receive no cash distributions from the Trust.
Item 1B.
Unresolved Staff Comments
None.
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Item 2.
Properties
Description of the Underlying Properties
The underlying properties consist of Whitings net interests in certain oil and natural gas producing properties as of the date of the conveyance of the NPI to the Trust, which are located primarily
in the Rocky Mountains, Mid-Continent, Permian Basin and Gulf Coast regions of the United States. The underlying properties include interests in 3,081 gross (368.0 net) producing oil and natural gas wells located in 166 fields on 206,716 gross
(71,663 net) acres in 14 states. Whiting has acquired interests in these properties through various acquisitions that have occurred during its 28 year existence prior to the conveyance. For the year ended December 31, 2012, the net production
attributable to the underlying properties was 1,204 MBOE or 3.3 MBOE/d. Whiting operates approximately 65% of the underlying properties based on the December 31, 2012 standardized measure of discounted future net cash flows.
Whitings interests in the oil and natural gas properties comprising the underlying properties require Whiting to bear its
proportionate share, along with the other working interest owners, of the costs of development and operation of such properties. Many of the properties comprising the underlying properties are burdened by non-working interests owned by third parties
and royalty interests retained by the owners of the land subject to the working interests. These landowners royalty interests typically entitle the landowner to receive at least 12.5% of the revenue derived from oil and natural gas production
from wells drilled on the landowners land, without any deduction for drilling costs or other costs related to production of oil and natural gas. A working interest percentage represents a working interest owners proportionate ownership
interest in a property in relation to all other working interest owners in that property, whereas a net revenue interest is a working interest owners percentage of production and revenue, after reducing such interest by the percentage of
burdens on production such as royalties and overriding royalties.
The NPI entitles the Trust to receive 90% of the net
proceeds from the sale of 9.11 MMBOE (8.20 MMBOE at the 90% NPI) of production from the underlying properties. As of December 31, 2012, on a cumulative accrual basis 6.10 MMBOE (74%) of the Trusts total 8.20 MMBOE have been produced
and sold, a cumulative 0.02 MMBOE have been divested, and the remaining balance is expected to be produced by June 30, 2015 based on the Trusts year-end 2012 reserve report. However, the reserve report is based on the assumptions included
therein. See Risk Factors in Item 1A of this Annual Report on Form 10-K for additional discussion. The rate of future production cannot be predicted with certainty, and 9.11 MMBOE (8.20 MMBOE at the 90% NPI) may be produced before
or after the currently projected date. The proved reserves attributable to the underlying properties include all proved reserves expected to be economically produced during the remaining full life of the properties, whereas the Trust is entitled to
only receive 90% of the net proceeds from the sale of production of oil, natural gas and natural gas liquids attributable to the underlying properties during the term of the NPI.
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Whitings interest in the underlying properties, after deducting the NPI, entitles it
to 10% of the net proceeds from the sale of oil, natural gas and natural gas liquids production attributable to the underlying properties during the term of the NPI and all of the net proceeds thereafter. In addition, the Trust units retained by
Whiting represent 15.8% of the Trust units outstanding. Whitings retained ownership interests in the underlying properties and its ownership of Trust units considered together entitle Whiting to receive approximately 24.2% of the net proceeds
from the underlying properties during the term of the Trust, thereby providing Whiting an incentive to operate (or cause to be operated) the underlying properties in an efficient and cost-effective manner. In addition, Whiting has agreed to operate
these properties as a reasonably prudent operator in the same manner that it would operate them if these properties were not burdened by the NPI, and Whiting has agreed to use commercially reasonable efforts to cause the other operators to operate
these properties in the same manner.
In general, the producing wells to which the underlying properties relate have
established production profiles. Based on the reserve report, annual production from the underlying properties is expected to decline at rates ranging from 9% to 11% annually from 2013 through the estimated June 30, 2015 NPI termination date.
However, cash distributions to unitholders may decline at a faster rate than the rate of production due to fixed and semi-variable costs attributable to the underlying properties.
Reserves
As of December 31, 2012, all of the Trusts oil and
gas reserves are attributable to properties within the United States. The following table summarizes estimated proved reserves (developed and undeveloped) and the standardized measure of discounted future net cash flows as of December 31, 2012
based on average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended December 31, 2012) attributable to the Trust based on the term of its NPI
and the underlying properties on a full economic life basis (dollars in thousands):
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Whiting USA Trust
I
(2)
(90% NPI through June 2015)
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Underlying Properties
(100% Full
Economic Life)
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Oil
(3)
(MBbl)
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Natural Gas
(Mcf)
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MBOE
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Oil
(3)
(MBbl)
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Natural Gas
(Mcf)
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MBOE
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Proved reserves:
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Developed
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1,447
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3,975
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2,110
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8,101
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16,274
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10,813
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Undeveloped
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-
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-
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-
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-
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-
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-
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Total provedDecember 31, 2012
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1,447
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3,975
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2,110
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8,101
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16,274
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10,813
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Standardized measure(1)
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$ 68,953
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$ 188,728
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45
(1)
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Standardized measure of discounted future net cash flows as of December 31, 2012. No provision for federal or state income taxes has been
provided because taxable income is passed through to the unitholders of the Trust. Therefore, the standardized measure of the Trust and of the underlying properties is equal to their corresponding pre-tax PV 10% values.
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(2)
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The Trusts estimated proved reserves as of December 31, 2012 on a 90% basis were 2,110 MBOE, which reserve amount includes only those
quantities of proved reserves in the underlying properties that are available to satisfy the interests of Trust unitholders and does not include the remaining 10% of proved reserves in the underlying properties to which only Whiting would be
entitled.
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(3)
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Oil includes natural gas liquids.
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The above tables do not include any proved undeveloped reserve quantities as of December 31, 2012 because the underlying properties consist of mature producing properties that are essentially fully
developed. Technical studies have not identified any drilling locations that meet the criteria of proved undeveloped reserves, nor has any future capital been committed for the development of proved undeveloped reserves on the underlying properties.
Proved reserves.
Estimates of proved reserves are inherently imprecise and are continually subject to revision based
on production history, results of additional exploration and development, price changes and other factors. Oil and gas reserve quantities and related discounted future net cash flows have been derived from oil and gas prices calculated using an
average of the first-day-of-the month price for each month within the most recent 12 months, pursuant to current SEC and FASB guidelines. Assumptions used to estimate reserve quantities and related discounted future net cash flows also include costs
for estimated future production expenditures required to produce the proved reserves as of December 31, 2012. Future net cash flows are discounted at an annual rate of 10%. There is no provision for federal income taxes with respect to the
future net cash flows attributable to the underlying properties or to the NPI because future net revenues are not subject to taxation at the Trust level. See Federal Income Tax Matters in Item 1 of this Annual Report on Form 10-K
for more information.
A rollforward of changes in net proved reserves attributable to the Trust from January 1, 2010 to
December 31, 2012, and the calculation of the standardized measure of the related discounted future net revenues are contained in the Supplemental Oil And Gas Reserve Information (Unaudited) in the notes to the financial statements of the Trust
included in this Annual Report on Form 10-K. Whiting has not filed reserve estimates covering the underlying properties with any other federal authority or agency.
In 2012, revisions to previous estimates decreased proved reserves by a net amount of 17 MBOE. Included in these revisions were 0.2 Bcf of downward adjustments to natural gas, primarily due to lower gas
prices of $3.07 per Mcf in reserve estimates at December 31, 2012, as compared to gas prices of $4.10 per Mcf at December 31, 2011 and 19 MBbl of upward adjustments to crude oil reserves, primarily due to increased estimates of future
production resulting from recent workovers and well performance.
46
Preparation of reserves estimates.
Whiting has advised the Trust that it maintains
adequate and effective internal controls over the reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are comprised of technical information,
financial data, ownership interests and production data. All field and reservoir technical information, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land
personnel to discuss field performance. Current revenue and expense information is obtained from Whitings accounting records, which are subject to their own set of internal controls over financial reporting. Internal controls over financial
reporting are assessed for effectiveness annually using the criteria set forth in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as
commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete.
Whitings current ownership in mineral interests and well production data are also subject to the aforementioned internal controls over financial reporting, and they are incorporated in the reserve database as well and verified to ensure their
accuracy and completeness. Once the reserve database has been entirely updated with current information, and all relevant technical support material has been assembled, the Trusts independent engineering firm Cawley, Gillespie &
Associates, Inc. (CG&A) meets with Whitings technical personnel in Whitings Denver and Midland offices to review field performance. Following these reviews the reserve database is furnished to CG&A so that they can
prepare their independent reserve estimates and final report. Access to Whitings reserve database is restricted to specific members of the reservoir engineering department.
CG&A is a Texas Registered Engineering Firm. The primary contact at CG&A is Mr. Robert Ravnaas, President. Mr. Ravnaas
is a State of Texas Licensed Professional Engineer. See Appendix 1 and Exhibit 99 of this Annual Report on Form 10-K for the Report of Cawley, Gillespie & Associates, Inc. and further information regarding the professional qualifications of
Mr. Ravnaas.
Whitings Vice President of Reservoir Engineering and Acquisitions is responsible for overseeing the
preparation of the reserves estimates. He has over 39 years of experience, the majority of which has involved reservoir engineering and reserve estimation, holds a Bachelors degree in Petroleum Engineering from the University of Wyoming, holds
an MBA from the University of Denver and is a registered Professional Engineer. He has also served on the national Board of Directors of the Society of Petroleum Evaluation Engineers.
As noted above, the current reserve report projects that 9.11 MMBOE attributable to the NPI will be produced from the underlying
properties by June 30, 2015, which differs from the August 31, 2015 projected date in the December 31, 2011 reserve report. This change is primarily due to increased estimates of future production resulting from recent workovers and
the completion of wells drilled in 2012. The projected time to produce the remaining reserves
47
attributable to the Trust is therefore reduced. Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information
becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the estimates. In addition, the reserves and net revenues attributable to the NPI include only 90% of the reserves
attributable to the underlying properties that are expected to be produced within the term of the NPI.
Producing Acreage and Well Counts
For the following data, gross refers to the total wells or acres in the oil and natural gas properties in
which Whiting owns a working interest and net refers to gross wells or acres multiplied by the percentage working interest owned by Whiting and in turn attributable to the underlying properties. Although many of Whitings wells
produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas production.
The underlying properties are interests in developed properties located in oil and natural gas producing regions outlined in the chart below. The following is a summary of the number of fields and
approximate acreage of these properties by region at December 31, 2012. Undeveloped acreage is not significant.
|
|
|
|
|
|
|
|
|
Number of
|
|
Total Acreage
|
Region
|
|
Fields
|
|
Gross
|
|
Net
|
Mid-Continent
|
|
56
|
|
67,201
|
|
30,858
|
Rocky Mountains
|
|
61
|
|
73,467
|
|
28,016
|
Permian Basin
|
|
28
|
|
31,237
|
|
7,815
|
Gulf Coast
|
|
21
|
|
34,811
|
|
4,974
|
|
|
|
|
|
|
|
Total
|
|
166
|
|
206,716
|
|
71,663
|
|
|
|
|
|
|
|
The following is a summary of the producing wells on the underlying properties as of December 31, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated Wells
|
|
|
Non-Operated Wells
|
|
|
Total Wells
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Oil
|
|
|
275
|
|
|
|
173.2
|
|
|
|
2,112
|
|
|
|
84.1
|
|
|
|
2,387
|
|
|
|
257.3
|
|
Natural gas
|
|
|
71
|
|
|
|
49.0
|
|
|
|
623
|
|
|
|
61.7
|
|
|
|
694
|
|
|
|
110.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
346
|
|
|
|
222.2
|
|
|
|
2,735
|
|
|
|
145.8
|
|
|
|
3,081
|
|
|
|
368.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following is a summary of the number of developmental wells drilled on the underlying properties
during the last three years. A dry well is an exploratory, development or extension
48
well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. A productive well is an exploratory, development or extension
well that is not a dry well. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities of reserves
found. Whiting did not drill any exploratory wells on the underlying properties during the periods presented. There were three wells that were in the process of being drilled as of December 31, 2012.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2012
|
|
|
2011
|
|
|
2010
|
|
|
|
Gross
|
|
Net
|
|
|
Gross
|
|
Net
|
|
|
Gross
|
|
Net
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil wells
|
|
5
|
|
|
0.5
|
|
|
7
|
|
|
1.0
|
|
|
9
|
|
|
2.5
|
|
Natural gas wells
|
|
3
|
|
|
-
|
|
|
6
|
|
|
0.2
|
|
|
3
|
|
|
-
|
|
Dry
|
|
-
|
|
|
-
|
|
|
2
|
|
|
0.5
|
|
|
1
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
8
|
|
|
0.5
|
|
|
15
|
|
|
1.7
|
|
|
13
|
|
|
2.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Production
The table below shows total oil and gas production, average sales prices and average production costs attributable to underlying properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2012
|
|
|
2011
|
|
|
2010
|
|
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil production (MBbl)
|
|
|
753
|
|
|
|
740
|
|
|
|
792
|
|
Natural gas production (MMcf)
|
|
|
2,705
|
|
|
|
2,778
|
|
|
|
3,156
|
|
Total production (MBOE)
|
|
|
1,204
|
|
|
|
1,203
|
|
|
|
1,318
|
|
Average daily production (MBOE/d)
|
|
|
3.3
|
|
|
|
3.3
|
|
|
|
3.6
|
|
Magnolia field production:
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil production (MBbl)
|
|
|
120
|
|
|
|
128
|
|
|
|
124
|
|
Natural gas production (MMcf)
|
|
|
167
|
|
|
|
165
|
|
|
|
166
|
|
Total production (MBOE)
|
|
|
147
|
|
|
|
156
|
|
|
|
152
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
79.33
|
|
|
$
|
82.63
|
|
|
$
|
66.58
|
|
Natural gas (per Mcf)
|
|
$
|
2.86
|
|
|
$
|
4.17
|
|
|
$
|
4.37
|
|
Production costs per BOE
(2)
|
|
$
|
24.01
|
|
|
$
|
20.11
|
|
|
$
|
17.07
|
|
(1)
|
Magnolia field was the only field that contained 15% or more of the total proved reserve volumes at December 31, 2012.
|
(2)
|
Production costs reported above exclude from lease operating expenses ad valorem taxes of $1.1 million ($0.94/BOE), $1.1 million ($0.88/BOE) and
$1.0 million ($0.78/BOE) for the years ended December 31, 2012, 2011 and 2010, respectively.
|
49
Producing wells the Trust has an interest in are part of 14 enhanced oil recovery waterflood
projects, and aggregate production from such enhanced oil recovery fields averaged 687 BOE/d during 2012 or 21% of 2012 daily production from the underlying properties. For these areas, Whiting needs to use enhanced recovery techniques in order to
maintain oil and gas production from these fields.
Delivery Commitments
Neither the Trust nor the underlying properties are committed to deliver fixed quantities of oil or gas in the future under existing
contracts or agreements.
Major Producing Areas
The underlying properties are located in several major onshore producing basins in the continental United States. Whiting believes this broad distribution provides a buffer against regional trends that
may negatively impact production or prices. Based on the standardized measure of discounted future net cash flows at December 31, 2012, approximately 65% of these properties were operated by Whiting. Based on annual 2012 production attributable
to the underlying properties, approximately 63% of production was crude oil and natural gas liquids and 37% of production was natural gas. These properties are located in mature fields and have established production profiles. However, production
and distributions to the Trust will decline over time.
Mid-Continent Region.
The underlying properties in the
Mid-Continent region are located in Arkansas, Oklahoma, Kansas and Michigan. These properties include 56 fields of which Whiting operates wells in 25 of these fields. There are two significant fields located in Arkansas. The Magnolia Smackover Pool
Unit, the largest single field in the underlying properties, produces from the Smackover Lime. The second Arkansas field is the Stephens-Smart field, producing from the Buckrange and Travis Peak. The major fields and areas in Oklahoma are located in
the Anadarko Basin and include Putnam Field, Mocane-Laverne Gas Area, Sho-Vel-Tum Field and Nobscot Northwest Field, which primarily produce from the Oswego, Hunton, Penn, Morrow, Red Fork and Cottage Grove zones. Case Field is the major Michigan
field in the region and produces from the Silurian Niagaran zone. For the year ended December 31, 2012, the net production attributable to the underlying properties in the region was 479.7 MBOE or 1.3 MBOE/d.
Rocky Mountains Region.
The underlying properties in the Rocky Mountains region are located in two distinct areas. The first, from
which crude oil is primarily produced, includes the Williston Basin in North Dakota and Montana as well as the Bighorn and Powder River Basins of Wyoming, while the second, from which natural gas is primarily produced, includes southwest Wyoming,
Colorado and Utah. These properties include 61 fields, and Whiting operates wells in 31 of these fields. The major North Dakota fields in this region include the Bell Field and the Fryburg Field that produce from Tyler sandstone; the Whiskey Joe,
Teddy Roosevelt, Sherwood and Davis Creek Fields that produce from various intervals in the
50
Madison; the Hiline Unit that produces from the Lodgepole; and the Big Dipper Field that produces from the Duperow and Red River zones. In Montana, the major fields include the Bainville Field
and Palomino Fields that produce primarily from the Nisku zone, and the Oxbow Field that produces from the Nisku and Red River zones. The major Wyoming fields in this region include the Sage Creek Field in the Bighorn Basin that produces from the
Tensleep and Madison zones and the Kiehl Field in the Powder River Basin, which produces from the Minnelusa formation and is under waterflood. The Ignacio Blanco Field is the major Colorado field in this region and produces from the Fruitland Coal
zone. For the year ended December 31, 2012, the net production attributable to the underlying properties in the region was 425.3 MBOE or 1.2 MBOE/d.
Permian Basin Region.
The Permian Basin Region is one of the major hydrocarbon producing provinces in the continental United States. The underlying properties in the Permian Basin region are
located in Texas and New Mexico. These properties include 28 fields, and Whiting operates wells in 9 of these fields. The major fields in this region include the Iatan East Howard Field, which produces from the San Andres, Glorieta and Clearfork
zones; the Fullerton Field, which is unitized and produces from the Clearfork zone; and the Patricia Field, which produces from the Sprayberry and Fusselman zones. For the year ended December 31, 2012, the net production attributable to the
underlying properties in the region was 178.1 MBOE or 0.5 MBOE/d.
Gulf Coast Region.
The underlying properties in the
Gulf Coast region are located in Texas, Louisiana, Mississippi and Alabama. These properties include 21 onshore fields, and Whiting operates wells in one of these fields. The major field in this region is the Mestena Grande Field located in Texas,
which produces from the Queen City zone. For the year ended December 31, 2012, the net production attributable to the underlying properties in the region was 120.8 MBOE or 0.3 MBOE/d.
Abandonment and Sale of Underlying Properties
Whiting has the right to
abandon its interest in any well or property comprising a portion of the underlying properties if, in its opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities. To reduce or eliminate the
potential conflict of interest between Whiting and the Trust in determining whether a well is capable of producing in commercially paying quantities, Whiting has agreed to operate the underlying properties as a reasonably prudent operator in the
same manner that it would operate if these properties were not burdened by the NPI, and Whiting has agreed to use commercially reasonable efforts to cause the other operators to operate these properties in the same manner. For the years ended
December 31, 2012, 2011 and 2010, there were 9, 8 and 20 gross wells, respectively, that were plugged and abandoned on the underlying properties, based on the determination that such wells were no longer economic to operate.
In addition, Whiting may, without the consent of the Trust unitholders, require the Trust to release the NPI associated with any lease
that accounts for less than or equal to 0.25% of the
51
total production from the underlying properties in the prior 12 months and provided that the NPI covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value
to the Trust of $500,000. These releases will be made only in connection with a sale by Whiting of the relevant underlying properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such NPI. Any net
sales proceeds paid to the Trust are distributable to Trust unitholders in the quarter in which they are received. During 2012, Whiting had no divestitures of Trust properties. Whiting includes all such proceeds from Trust property divestitures in
its NPI distributions to the Trust.
Title to Properties
The underlying properties are subject to certain burdens that are described in more detail below. To the extent that these burdens and obligations affect Whitings rights to production and the value
of production from the underlying properties, they have been taken into account in calculating the Trusts interests and in estimating the size and the value of the reserves attributable to the underlying properties.
Whitings interests in the oil and natural gas properties comprising the underlying properties are typically subject, in one degree
or another, to one or more of the following:
|
|
|
royalties, overriding royalties and other burdens, express and implied, under oil and natural gas leases;
|
|
|
|
overriding royalties, production payments and similar interests and other burdens created by Whiting or its predecessors in title;
|
|
|
|
a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements
that may affect the underlying properties or their title;
|
|
|
|
liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and
contractors, and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;
|
|
|
|
pooling, unitization and communitization agreements, declarations and orders;
|
|
|
|
easements, restrictions, rights-of-way and other matters that commonly affect property;
|
|
|
|
conventional rights of reassignment that obligate Whiting to reassign all or part of a property to a third party if Whiting intends to
release or abandon such property; and
|
|
|
|
rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the underlying properties and the NPI
therein.
|
52
Whiting has informed the Trustee that Whiting believes the burdens and obligations affecting
the properties comprising the underlying properties are conventional in the industry for similar properties. Whiting also has informed the Trustee that Whiting believes that the existing burdens and obligations do not, in the aggregate, materially
interfere with the use of the underlying properties and do not materially adversely affect the value of the NPI.
Whiting
acquired the underlying properties in various transactions that have occurred during its 28 year existence prior to the conveyance. At the time of its acquisitions of the underlying properties, Whiting undertook a title examination of these
properties.
Net profits interests are non-operating, non-possessory interests carved out of the oil and natural gas leasehold
estate, but some jurisdictions have not directly determined whether a NPI is a real or a personal property interest. Whiting has recorded the conveyance of the NPI in the relevant real property records of all applicable jurisdictions. Whiting has
informed the Trustee that Whiting believes the delivery and recording of the conveyance creates a fully conveyed and vested property interest under the applicable states laws, but because there is no direct authority to this effect in some
jurisdictions, this may not always be the result. Whiting has also informed the Trustee that Whiting believes that it is possible the NPI may not be treated as a real property interest under the laws of certain of the jurisdictions where the
underlying properties are located. Whiting has also informed the Trustee that Whiting believes that, if, during the term of the Trust, Whiting becomes involved as a debtor in a bankruptcy proceeding, the NPI relating to the underlying properties in
most, if not all, of the jurisdictions should be treated as a fully conveyed property interest. In such a proceeding, however, a determination could be made that the conveyance constitutes an executory contract and that the NPI is not a fully
conveyed property interest under the laws of the applicable jurisdiction, and if such contract were not to be assumed in a bankruptcy proceeding involving Whiting, the Trust would be treated as an unsecured creditor of Whiting with respect to such
NPI in the pending bankruptcy proceeding. Although no assurance can be given, Whiting has informed the Trustee that Whiting believes that the conveyance of the NPI relating to the underlying properties in most, if not all, of the jurisdictions of
which these properties are located should not be subject to rejection in a bankruptcy proceeding as an executory contract.
Item 3.
Legal Proceedings
Currently, there are not any legal proceedings pending to which the Trust is a
party or of which any of its property is the subject.
Item 4.
Mine Safety Disclosures
Not applicable.
53
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
|
|
|
|
|
WHITING USA TRUST I
|
|
|
By:
|
|
THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.
|
|
|
By:
|
|
/s/ MIKE ULRICH
|
|
|
Mike Ulrich
Vice President
|
March 15, 2013
The Registrant, Whiting USA Trust I, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are
available and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that such function exists pursuant to the terms of the Trust agreement under which it serves.
Appendix 1
Cawley, Gillespie & Associates, Inc.
PETROLEUM CONSULTANTS
|
|
|
|
|
13640 BRIARWICK DRIVE, SUITE 100
|
|
306 WEST SEVENTH STREET, SUITE 302
|
|
1000 LOUISIANA STREET, SUITE 625
|
AUSTIN, TEXAS 78729-1707
|
|
FORT WORTH, TEXAS 76102-4987
|
|
HOUSTON, TEXAS 77002-5008
|
512-249-7000
|
|
817-336-2461
|
|
713-651-9944
|
January 11, 2013
Whiting USA Trust I
1700 Broadway, Suite 2300
Denver, Colorado 80290-2300
|
|
|
|
|
|
|
Re:
|
|
Evaluation Summary SEC Price
|
|
|
|
|
Whiting USA Trust I Underlying
Properties
Proved Producing Reserves
Certain Properties Located in Various
States
As of December 31, 2012
|
|
|
|
|
|
|
|
Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue
|
Gentlemen:
As requested, we are submitting our estimates of proved producing reserves and forecasts of economics attributable to the underlying properties, from which a net profits interest has been formed and
conveyed by Whiting Petroleum Corporation to the Whiting USA Trust I. These certain oil and gas properties are located in North Dakota, Texas, Oklahoma, Arkansas, Montana, Wyoming, Michigan, New Mexico, Alabama, Louisiana, Colorado, Kansas, Utah and
Mississippi. Also included in the table below are the proved reserves attributable to the same underlying properties estimated to be produced by June 30, 2015, which is the estimated date of termination for Whiting USA Trust I. This report,
completed January 11, 2013 covers 100% of the proved producing reserves estimated for Whiting USA Trust I. This report includes results for an SEC pricing scenario. The results of this evaluation are presented in the accompanying tabulations,
with a composite summary presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Producing
|
|
|
|
|
|
Underlying
Properties
Full Economic Life
|
|
|
Underlying Properties
Reserves Estimated to be Produced
By June 30, 2015
|
|
|
|
|
|
|
|
|
Net Reserves
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
- Mbbl
|
|
|
7,799.6
|
|
|
|
1,473.8
|
|
Gas
|
|
- MMcf
|
|
|
16,273.9
|
|
|
|
4,416.8
|
|
NGL
|
|
- Mbbl
|
|
|
301.5
|
|
|
|
134.1
|
|
Equivalent*
|
|
- Mbbl
|
|
|
10,813.4
|
|
|
|
2,344.1
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
- M$
|
|
|
672,464.9
|
|
|
|
127,302.8
|
|
Gas
|
|
- M$
|
|
|
50,533.5
|
|
|
|
13,555.7
|
|
NGL
|
|
- M$
|
|
|
12,817.4
|
|
|
|
5,259.9
|
|
Severance Taxes
|
|
- M$
|
|
|
54,927.6
|
|
|
|
11,404.1
|
|
Ad Valorem Taxes
|
|
- M$
|
|
|
9,452.0
|
|
|
|
1,795.0
|
|
Operating Expenses
|
|
- M$
|
|
|
328,260.3
|
|
|
|
47,358.7
|
|
Investments
|
|
- M$
|
|
|
0.0
|
|
|
|
0.0
|
|
Net Operating Income
|
|
- M$
|
|
|
343,175.8
|
|
|
|
85,560.5
|
|
Discounted @ 10%
|
|
- M$
|
|
|
188,728.4
|
|
|
|
76,614.6
|
|
|
|
*Calculated based on an energy equivalent that one Bbl of crude oil equals six Mcf of natural gas and one
Bbl of crude oil equals one Bbl of natural gas liquids.
The discounted cash flow value shown in the previous table should not
be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc.
Hydrocarbon Pricing
As requested for the SEC scenario, initial WTI spot oil and Henry Hub Gas Daily prices of $94.71 per bbl and $2.76
per MMBtu, respectively, were adjusted individually to WTI posted pricing at $91.32 per bbl and Houston Ship Channel pricing at $2.71 per MMBtu, as of December 31, 2012. Further adjustments were applied on a lease level basis for oil price
differentials, gas price differentials and heating values as furnished by your office. Prices were not escalated in the SEC scenario. The average adjusted prices used in the estimation of proved producing reserves for the underlying properties full
economic life were $86.22 per bbl of oil, $42.52 per bbl of natural gas liquids and $3.11 per mcf of natural gas. For the proved producing reserves of the underlying properties estimated to be produced by June 30, 2015, the average adjusted
prices were $86.38 per bbl of oil, $39.22 per bbl of natural gas liquids and $3.07 per mcf of natural gas.
Capital, Expenses and Taxes
Capital expenditures, lease operating expenses and Ad Valorem tax values were forecast as provided by your office. As you explained, the
capital costs were based on the most current estimates, lease operating expenses were based on the analysis of historical actual expenses, operating overhead is included for operated properties and no credit or deduction is made for producing
overhead paid to the company by other owners of the operated properties. Capital costs and lease operating expenses were held constant in accordance with SEC guidelines. Severance tax rates were applied at normal state percentages of oil and gas
revenue.
SEC Conformance Regulations
The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined on pages 3 and 4 of the Appendix. The reserves and economics are predicated on
regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves
and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
Reserve Estimation Methods
The methods employed in estimating
reserves are described in page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production
history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.
Miscellaneous
An on-site field inspection of the properties has
not been performed. The mechanical operation or conditions of the wells and their related facilities have
not
been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental
liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included.
The reserve estimates were based on interpretations of factual data furnished by your office. We have used all methods and procedures as we considered necessary under the circumstances to prepare the
report. We believe that the assumptions, data, methods and procedures were appropriate for the purpose served by this report. Production data, gas prices, gas price differentials, expense data, tax values and ownership interests were also supplied
by you and were accepted as furnished. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing
has come to our attention, however, that would cause us to believe that we are not justified in relying on such data.
The professional qualifications of the undersigned, the technical person primarily
responsible for the preparation of this report, are included as an attachment to this letter.
|
Yours very truly,
|
|
/s/ Robert D. Ravnaas
|
Robert D. Ravnaas, P.E.
|
President
|
Cawley, Gillespie & Associates
|
Texas Registered Engineering Firm F-693
|
APPENDIX
Explanatory Comments for Individual Tables
HEADINGS
Table Number
Effective Date of the Evaluation
Identity of Interest Evaluated
Reserve Classification and Development Status
Operator Property Name
Field (Reservoir) Names County, State
FORECAST
|
|
|
(Columns)
|
|
|
(1) (11) (21)
|
|
Calendar
or
Fiscal
years/months commencing on effective date.
|
(2) (3) (4)
|
|
Gross Production
(8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard
conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.
|
(5) (6) (7)
|
|
Net Production
accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in
interest and gas shrinkage.
|
(8)
|
|
Average (volume weighted)
gross liquid price
per barrel before deducting production-severance taxes.
|
(9)
|
|
Average (volume weighted)
gross gas price
per Mcf before deducting production-severance taxes.
|
(10)
|
|
Average (volume weighted)
gross NGL price
per barrel before deducting production-severance taxes.
|
(12)
|
|
Revenue
derived from oil sales -- column (5) times column (8).
|
(13)
|
|
Revenue
derived from gas sales -- column (6) times column (9).
|
(14)
|
|
Revenue
derived from NGL sales -- column (7) times column (10).
|
(15)
|
|
Revenue
derived from other sources.
|
(16)
|
|
Revenue
derived from hedge positions.
|
(17)
|
|
Total Revenue
sum of column (12) through column (16).
|
(18)
|
|
Production-Severance taxes
deducted from gross oil and NGL revenue.
|
(19)
|
|
Production-Severance taxes
deducted from gross gas revenue.
|
(20)
|
|
Revenue after taxes
column (17) less column (18) and column (19).
|
(22)
|
|
Operating Expenses
are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and
gas producers known as COPAS.
|
(23)
|
|
Ad Valorem taxes
.
|
(24)
|
|
Work-over Expenses
are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
|
(25)
|
|
3rd Party COPAS
are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
|
(26)
|
|
Other Deductions
may include compression-gathering expenses, transportation costs and water disposal
costs.
|
Cawley,
Gillespie & Associates, Inc.
Appendix
Page 1
|
|
|
(27)
|
|
Investments
, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging
and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
|
(28) (29)
|
|
Future Net Cash Flow
is column (18) less the total of column (19), column (22), column (24), column (25), column (26) and column (27). The data in column (28) are
accumulated in column (29). Federal income taxes have not been considered.
|
(30)
|
|
Cumulative Discounted Cash Flow
is calculated by discounting monthly cash flows at the specified annual rates.
|
|
MISCELLANEOUS
|
|
|
Input Data
|
|
Evaluation parameters such as rates, tax percentages, and expenses are shown below
columns (21-26).
|
Interests
|
|
Initial and final expense and revenue interests are shown below columns
(27-28).
|
DCF Profile
|
|
The cash flow discounted at six different rates are shown at the bottom of columns
(29-30). Interest has been compounded monthly.
|
Life
|
|
The economic life of the appraised property is noted in the lower right-hand corner
of the table.
|
Footnotes
|
|
Well ID information or other pertinent comments may be shown in the lower left-hand
footnotes.
|
Cawley,
Gillespie & Associates, Inc.
Appendix
Page 2
APPENDIX
Methods Employed in the Estimation of Reserves
The four methods customarily
employed in the estimation of reserves are (1)
production performance
, (2)
material balance
, (3)
volumetric
and (4)
analogy
. Most estimates, although based primarily on one
method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.
Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties.
Operators are generally required by regulatory authorities to file monthly production reports and
may
be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator
has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant
differences in the accuracy and reliability of estimates.
A brief discussion of each method, its basis, data requirements,
applicability and generalization as to its relative degree of accuracy follows:
Production performance
. This
method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only
information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as decline curve analysis. Both capacity and restricted
production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the
degree of accuracy increasing as production history accumulates.
Material balance
. This method employs the
analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by
analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is
applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility
versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable
only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and
quantity of data available.
Cawley,
Gillespie & Associates, Inc.
Appendix
Page 3
Volumetric
. This method employs analyses of physical measurements of rock and
fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most
applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be
recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of
accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.
Analogy
. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The
analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of
accuracy.
Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These
estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and
reservoir performance.
Cawley,
Gillespie & Associates, Inc.
Appendix
Page 4
APPENDIX
Reserve Definitions and Classifications
The Securities and Exchange
Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:
(22)
Proved oil and gas reserves
. Proved oil and gas reserves are
those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically produciblefrom a given date forward, from known reservoirs, and under existing economic
conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or
probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of a reservoir considered as proved includes: (A) The area
identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the
basis of available geoscience and engineering data.
(ii) In the absence
of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with
reasonable certainty.
(iii) Where direct observation from well
penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance
data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved
recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir
as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic
producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the
Cawley,
Gillespie & Associates, Inc.
Appendix
Page 5
first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
(6)
Developed oil and gas reserves
. Developed oil and gas reserves are
reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which
the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the
time of the reserves estimate if the extraction is by means not involving a well.
(31)
Undeveloped oil and gas reserves
. Undeveloped oil and gas
reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting
development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a
development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or
other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using
reliable technology establishing reasonable certainty.
(18)
Probable reserves
. Probable reserves are those additional
reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus
probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved
reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas
that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
Cawley,
Gillespie & Associates, Inc.
Appendix
Page 6
(iii) Probable reserves estimates also
include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
(17)
Possible reserves
. Possible reserves are those additional
reserves that are less certain to be recovered than probable reserves.
(i) When deterministic methods are used, the total quantities ultimately recovered
from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the
proved plus probable plus possible reserves estimates.
(ii) Possible
reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are
unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii) Possible reserves also include incremental quantities associated with a
greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus possible reserves
estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v) Possible reserves may be assigned where geoscience and engineering data identify
directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a
wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in
communication with the proved reservoir.
(vi) Pursuant to paragraph
(22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the
reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil
or gas based on reservoir fluid properties and pressure gradient interpretations.
Instruction 4 of Item 2(b) of
Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation SK.
This is relevant in that Instruction 2 to paragraph (a)(2) states: The registrant is
permitted, but not required
, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.
Cawley,
Gillespie & Associates, Inc.
Appendix
Page 7
(26)
Reserves
. Reserves
are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a
reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the
project.
Note to paragraph (26)
: Reserves should not be assigned to adjacent reservoirs isolated by major,
potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of
reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Cawley,
Gillespie & Associates, Inc.
Appendix
Page 8
Cawley, Gillespie & Associates, Inc.
PETROLEUM CONSULTANTS
|
|
|
|
|
9601 AMBERGLEN BLVD., SUITE 117
|
|
306 WEST SEVENTH STREET, SUITE 302
|
|
1000 LOUISIANA STREET, SUITE 625
|
AUSTIN, TEXAS 78729-1106
|
|
FORT WORTH, TEXAS 76102-4987
|
|
HOUSTON, TEXAS 77002-5008
|
512-249-7000
|
|
817-336-2461
|
|
713-651-9944
|
Professional Qualifications of Robert D. Ravnaas, P.E.
President of Cawley, Gillespie & Associates
Mr. Ravnaas has been a Petroleum Consultant for Cawley, Gillespie & Associates (CG&A) since 1983, and
became President in 2011. He has completed numerous field studies, reserve evaluations and reservoir simulation, waterflood design and monitoring, unit equity determinations and producing rate studies. He has testified before the Texas Railroad
Commission in unitization and field rules hearings. Prior to CG&A he worked as a Production Engineer for Amoco Production Company. Mr. Ravnaas received a B.S. with special honors in Chemical Engineering from the University of Colorado at
Boulder, and a M.S. in Petroleum Engineering from the University of Texas at Austin. He is a registered professional engineer in Texas, No. 61304, and a member of the Society of Petroleum Engineers (SPE), the Society of Petroleum Evaluation
Engineers, the American Association of Petroleum Geologists and the Society of Professional Well Log Analysts.