Item 1.
Business
General
Whiting USA Trust I is a statutory trust formed in October 2007 under the Delaware Statutory Trust Act, pursuant to a trust agreement (the Trust agreement) among Whiting Oil and Gas as
trustor, The Bank of New York Trust Company, N.A., as trustee (subsequently renamed The Bank of New York Mellon Trust Company, N.A., and hereinafter referred to as Trustee) and Wilmington Trust Company as Delaware Trustee (the
Delaware Trustee). The initial capitalization of the Trust estate was funded by Whiting in November 2007. The Trust maintains its offices at the office of the Trustee, at 919 Congress Avenue, Austin, Texas 78701. The telephone number of
the Trustee is (512) 236-6545.
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 SEC at
http://www.sec.gov
. In addition, the Trust will provide electronic and
paper copies of its recent filings free of charge upon request to the Trustee.
As of December 31,
2007, the Trust had no assets other than a de minimis cash balance from its initial capitalization and had conducted no operations other than organizational activities. In April 2008, the Trust issued 13,863,889 units of beneficial interest in the
Trust (Trust units) to Whiting in exchange for the conveyance of a term NPI by Whiting Oil and Gas. The NPI 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 3,062 gross (351.6 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 (such 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), which is estimated to occur on
March 31, 2015 based on the reserve report (as defined below). The Trust will soon thereafter wind up its affairs and terminate, after which it will pay no further distributions and the market price of Trust units will have declined to zero. To
the extent that the Trust units are trading at a price substantially in excess of the aggregate distributions that may be reasonably expected to be made prior to the termination of the Trust, the market price decline in Trust units is likely to
include one or more abrupt substantial decreases.
As of December 31, 2013, on a cumulative accrual basis
7.12 MMBOE (87%) 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 Properties-Description of
Underlying Properties-Reserves, and such reserve information is based upon a reserve report prepared by independent reserve engineers Cawley, Gillespie & Associates, Inc. for the underlying properties at December 31, 2013, which
we refer to as the
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reserve report. According to the reserve report, the portion of the 9.11 MMBOE (8.20 MMBOE at the 90% NPI) reserve quantities attributable to the NPI not yet produced or sold as
divestitures at December 31, 2013 is projected to be produced from the underlying properties by March 31, 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, 2013 was approximately 62% oil and approximately 38% 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, with the remainder being considered as a return on investment. As a result, the market price of the Trust units will decline to zero at
termination of the Trust.
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, which may be a non-interest bearing account, 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 underlying properties. The business and affairs of the Trust are administered 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
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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 2013, sales to Lion Oil Company, Enterprise South Texas and Plains Marketing LP accounted for 17%, 15% and 10%, respectively, of total oil and natural gas sales from the underlying properties. Whiting does not
believe that the potential loss of any of these purchasers is likely to present a material risk because there is significant competition among purchasers of crude oil and natural gas in the areas of the underlying properties, and if the underlying
properties were to lose any of their largest purchasers, several entities could reasonably be expected to purchase crude oil and natural gas produced from the underlying properties with little or no interruption to their 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, 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 NPI and estimated and actual future net revenues to the Trust. In light of the
many uncertainties that affect the supply and demand for oil and natural gas, neither the Trust nor Whiting can make reliable predictions of future oil and natural gas supply and demand, future product prices or the effect of future product prices
on the Trust.
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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 each of 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.
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
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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 and the market price of Trust units will have declined to zero. 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 dissolved.
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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 filed as an exhibit to
this Annual Report on Form 10-K.
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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
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. 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.
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 $7.1 million on the underlying properties in 2013. Such expenditures were not deducted from gross proceeds or Trust distributions in 2013, 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 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
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of the monthly charge averaged $465 per month per active operated well, which totaled $1.8 million for the four distributions made during the year ended December 31, 2013. 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 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 future production. The hedge contracts were in place during the 2012 and 2011 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.
Any amounts received by Whiting from the hedge contract counterparty upon settlements of the hedge contracts reduced 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 reduced the amount of net proceeds paid to the Trust.
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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 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.
In addition, Whiting may, without the consent of the Trust unitholders, require the Trust to sell the net profits
interest associated with any well or lease that accounts for less than or equal to 0.25% of the total production from the underlying properties in the prior 12 months, provided that the net profits interest covered by such releases cannot exceed,
during any 12-month period, an aggregate fair market value to the Trust of $0.5 million. These releases will be made only in connection with a sale by Whiting of the relevant underlying properties and are conditioned upon the Trust receiving an
amount equal to the fair value to the Trust of such NPI. Any net sales proceeds paid to the Trust are distributable to Trust unitholders in the quarter in which they are received. During 2013, Whiting divested two Trust properties which had no
associated proved reserves or sales proceeds.
For the underlying properties for which Whiting is the
designated operator, it 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 or any other operator 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.
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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 to the extent proposed) Treasury regulations thereunder and current administrative rulings and court
decisions, all of which are subject to change or different interpretation at any time, possibly with retroactive effect. 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 unincorporated business entity. No ruling has been or will be requested from
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 and receive 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
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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 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 (512) 236-6545, 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 2013 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
.
Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6%, and the highest marginal U.S. federal income tax rate applicable to long-term
capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and applicable to qualified dividends of individuals is 20%. The highest marginal U.S. federal income tax rate applicable to
corporations is 35%, and such rate applies to both ordinary income and capital gains.
Section 1411 of
the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income
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generally will include a Trust unitholders allocable share of the Trusts interest income plus the gain recognized from a sale of Trust units. In the case of an individual, the tax is
imposed on the lesser of (i) the individuals net investment income from all investments, or (ii) the amount by which the individuals modified adjusted gross income exceeds specified threshold levels depending on such
individuals federal income tax filing status. In the case of an estate or trust, the tax is imposed on the lesser of (x) undistributed net investment income, or (y) the excess adjusted gross income over the dollar amount at which the
highest income tax bracket applicable to an estate or trust begins.
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 release, discharge or emission of materials into the environment; the handling of hazardous materials; or otherwise relating to environmental protection. These laws and regulations
may, among other things:
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require the acquisition of a permit for drilling and other regulated activities;
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require the proper management and disposal of waste and 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 in sensitive areas, such as wilderness areas, wetlands, streams, coastal regions or areas that may
contain endangered or threatened species and their habitats;
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require investigatory or remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits, plug
and abandon wells and restore properties upon which wells are drilled;
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apply specific health and safety criteria addressing worker protection; 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 result in the
assessment of significant 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.
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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 and disposal of hazardous and non-hazardous wastes. Under delegation of authority from the U.S. 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 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 release of hazardous substances, hydrocarbons, waste products or other chemicals 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 and materials 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 give rise to potential liabilities for Whiting pursuant to CERCLA,
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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 waters of the United States 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 waters of the United States 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 from tight rock 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 to complete wells drilled on the underlying properties, and Whiting expects it will also be used in the future. The process is
typically regulated by state oil and gas commissions. However, the EPA recently issued guidance, which was published in the Federal Register on February 12, 2014, for permitting authorities and the industry regarding the process for obtaining a
permit for hydraulic fracturing involving diesel.
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 a draft final report for public comment and peer review in 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 for coalbed methane in 2013 and shale gas in 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, the U.S. Government Accountability Office and the White House Council for
Environmental Quality. The U.S. Department of the Interior released a draft proposed rule in May 2012 governing hydraulic fracturing on federal and Indian oil and natural gas leases to require disclosure of information regarding the chemicals used
in hydraulic fracturing, advance approval for well-stimulation activities, mechanical integrity testing of casing and monitoring of well-stimulation operations, and on May 24, 2013 the Federal Bureau of Land Management issued a revised draft of
the proposed rule. On November 20, 2013, the U.S. House of Representatives passed the Protecting States Rights to Promote American Energy Security Act, which would ban the U.S. Department of the Interior from regulating hydraulic
fracturing if enacted into law. In addition, legislation has been introduced in Congress from time to time to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.
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Also, some states have adopted, and other states are considering adopting,
regulations that could restrict or impose additional requirements on activities 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 in Texas) and the public. Such federal or state legislation could require the disclosure of
chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties
opposing hydraulic fracturing to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including
groundwater. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays, litigation risk
and potential increases in costs. Further, local governments may seek to adopt, and some have adopted, ordinances within their jurisdictions restricting the use of or regulating the time, place and manner of drilling or hydraulic fracturing. No
assurance can be given as to whether or not similar measures might be considered or implemented in the jurisdictions in which the underlying properties are located. If new laws, regulations or ordinances that significantly restrict or otherwise
impact hydraulic fracturing are passed by Congress or adopted in states or local municipalities where the underlying properties are located, 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.
Global Warming and Climate Change.
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 adopted 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. On June 3, 2010, the EPA also published regulations to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V permitting programs. On
June 26, 2012, the U.S. Circuit Court for the District of Columbia upheld the EPAs GHG regulations. Industry groups filed petitions for review of that decision with the U.S. Supreme Court and oral argument was scheduled for early 2014. In
November 2010, the EPA published its final rule expanding its existing GHG monitoring and reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. These requirements became
applicable in 2012 for emissions occurring in 2011, but industry groups have filed suit challenging certain provisions of the rules and are engaged in settlement negotiations to amend and correct the rules. 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
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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. The final cap-and-trade system began on January 1, 2012,
and legally enforceable compliance obligations began with 2013 emissions. 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 that 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 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, in 2012, the EPA finalized rules establishing 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 require the application of reduced emission completion techniques associated with the 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
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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 make a determination on listing more than 250 species as endangered or threatened under the ESA over the next several years. 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.
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. This process has the potential to delay the development of oil and natural gas projects. 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, 2013 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 2014 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.
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 shortly after the NPI termination date, currently estimated to be March 31, 2015. If the Trust units are trading at a price substantially in excess of the aggregate distributions that may reasonably be expected to be made prior to the
termination of the Trust, the price decline is likely to include one or more abrupt substantial decreases.
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
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numerous factors outside the control of the Trust, including prevailing sales prices of oil, natural gas and natural gas liquids production attributable to the underlying properties. Further, the
market price of the Trust units may be affected by factors other than the anticipated future distributions of the Trust. 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 shortly after the NPI termination date, which is currently estimated to be March 31, 2015. If the Trust units are trading at a price substantially in excess of
the aggregate distributions that may reasonably be expected to be made prior to the termination of the Trust, the price decline is likely to include one or more abrupt substantial decreases.
The reserves attributable to the underlying properties are depleting assets and production from those reserves will diminish over
time. Furthermore, the Trust is precluded from acquiring other oil and natural gas properties or NPI to replace the depleting assets and production.
The net proceeds payable to the Trust from the NPI are derived from the sale of oil, natural gas and natural gas liquids produced from the underlying properties. The reserves attributable to the
underlying properties are depleting assets, which means that such reserves will decline over time. The underlying properties reserve report reflects that cumulative past production (on an 8/8ths gross basis) through December 31, 2013
represents an aggregate depletion percentage of 94.4% 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 continue 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, remained consistent from 2011 to 2012 and declined 5.9% from 2012 to 2013. Also
based on the 2013 reserve report, oil and natural gas production attributable to the underlying properties are expected to decline at an estimated annualized rate of 12.6% from 2014 through the estimated March 31, 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 March 31, 2015. As
of December 31, 2013, on a cumulative accrual basis 7.12 MMBOE (87%) 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.
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Future maintenance projects on the underlying properties beyond those which
are currently estimated may affect the quantity of proved reserves that can be economically produced from the underlying properties. The timing and size of these projects will depend on, among other factors, the market prices of oil, natural gas and
natural gas liquids. If operators of the underlying properties do not implement required maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by Whiting or
estimated in the reserve report. In addition, Whiting is not required to make any capital expenditures.
Because the net proceeds payable to the Trust are derived from the sale of depleting assets, the portion of the
distributions to unitholders attributable to depletion should be considered a return of capital as opposed to a return on investment. Eventually, the NPI may cease to produce in commercial quantities and the Trust may, therefore, cease to receive
any distributions of net proceeds therefrom. In any case however, distributions will cease upon 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 approval (or lack thereof) to proceed with the Keystone XL pipeline from Hardesty,
Alberta to Cushing, Oklahoma 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 oil, natural gas and natural gas liquids prices 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, 2013, 2012 and 2011 totaled $1.4 million, $5.9 million and $4.5 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.
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
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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 from 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.
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 depends upon, among other things, the accuracy of the production and reserves estimated to be attributable to the underlying properties and the NPI. Estimating production and reserves is inherently uncertain. Ultimately,
actual production, revenues and expenditures for the underlying properties will vary from estimates, and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating production and reserves. Those
factors and assumptions include:
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historical production from the area compared with production rates from other producing areas;
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the assumed effect of governmental regulation; and
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assumptions about future prices of oil, natural gas and natural gas liquids, including differentials, production and development costs, gathering
and transportation costs, severance and excise taxes and capital expenditures.
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Changes in
these assumptions may materially alter production and reserve estimates. The estimated proved reserves attributable to the NPI and the 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 depends 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 reduces
Trust distributions by reducing the amount of net proceeds available for distribution. For example, accidents may occur that result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any
costs
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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. Please read Federal, state and local legislative and regulatory initiatives relating to hydraulic
fracturing... below in these Risk Factors for a discussion of the uncertainty involved in the regulation of hydraulic fracturing. 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, there have been recent accidents involving rail cars carrying crude oil, which resulted in the U.S. Department of
Transportation (the DOT) issuing an emergency order on February 25, 2014 that requires rail shippers to test the makeup of such crude oil before transporting it. This move follows the safety alert the DOT issued in January 2014 that
Bakken formation crude oil is more flammable than other types of crude oil. An accident involving rail cars could result in significant personal injuries and property and environmental damage. Additionally, added regulations in response to such
accidents could result in additional costs that could reduce proceeds available for distribution.
In
addition, 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.
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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 60% of the underlying properties based on the December 31, 2013 standardized measure of discounted future net cash flows. However, for
the 40% of the underlying properties that it does not operate, Whiting does not have control over normal operating procedures or expenditures relating to such properties. The failure of an operator to adequately perform operations or an
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 is 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.
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Whiting is not required to make capital expenditures on the underlying properties at
historical levels or at all. If Whiting does not make capital expenditures, then the timing of production from the underlying properties may not be accelerated.
Whiting has made capital expenditures on the underlying properties, which has increased production from the underlying
properties. However, Whiting has no contractual obligation to make capital expenditures on the underlying properties in the future. Furthermore, for properties on which Whiting is not designated as the operator, the decision whether to make capital
expenditures is made by the operator and Whiting has no control over the timing or amount of those capital expenditures. Whiting also has the right to non-consent and not participate in the capital expenditures on these properties, in which case
Whiting and the Trust will not receive the production resulting from such capital expenditures. Accordingly, it is likely that capital expenditures with respect to the underlying properties will vary from and may be less than historical
levels.
An increase in the differential or decrease in the premium between the NYMEX or other benchmark
prices of oil and natural gas and the wellhead price received could reduce cash distributions by the Trust and the value of Trust units.
Oil and natural gas production from the underlying properties generally trades at a discount, but sometimes at a premium, to the relevant benchmark prices, such as NYMEX. A negative difference between the
benchmark price and the price received is called a differential and a positive difference is called a premium. The differential and premium may vary significantly due to market conditions, the quality and location of production and other risk
factors. Whiting cannot accurately predict oil and natural gas differentials or premiums. Increases in the differential and decreases in the 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 precisely when that will occur.
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 reserve report prepared by the Trusts independent petroleum
engineer dated as of December 31, 2013 (the reserve report) projects that 9.11 MMBOE will have been produced and sold from the underlying properties by March 31, 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.
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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 approach and eventually reach zero shortly after 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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The documents governing the Trust generally do not provide a mechanism for resolving these conflicting interests.
The Trust is managed by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.
The business and affairs of the Trust are administered by the Trustee. The voting rights of a Trust
unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The Trust agreement
provides that the Trustee may only be removed and replaced by a vote of the holders of a majority of the outstanding Trust units at a special meeting of Trust unitholders called by either the Trustee or the holders of not less than 10% of the
outstanding Trust units. 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
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compel the Trustee to take specified actions. The Trust agreement expressly limits the Trust unitholders ability to directly sue Whiting or any other third party other than the Trustee. As
a result, the unitholders are not able to sue Whiting to enforce these rights.
Courts outside of Delaware may not
recognize the limited liability of the Trust unitholders provided under Delaware law.
Under the
Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations under the General Corporation Law of the State of Delaware. Courts in jurisdictions outside of
Delaware, however, may not give effect to such limitation.
The operations of the underlying properties may result in
significant costs and liabilities with respect to environmental and operational safety matters, which could reduce the amount of cash available for distribution to Trust unitholders.
Significant costs and liabilities can be incurred as a result of environmental and safety requirements applicable to the
oil and natural gas exploration, development and production activities of the underlying properties. These costs and liabilities could arise under a wide range of federal, regional, state and local environmental and safety laws, regulations, and
enforcement policies, which legal requirements have tended to become increasingly strict over time. Numerous governmental authorities, such as the 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.
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The operations of the underlying properties are subject to complex federal, state,
local and other laws and regulations that could adversely affect the cash distributions to the Trust unitholders.
The development and production operations of the underlying properties are subject to complex and stringent laws and regulations. In order to conduct the operations of the underlying properties in
compliance with these laws and regulations, Whiting and the other operators must obtain and maintain numerous permits, approvals and certificates from various federal, state, local and governmental authorities. Whiting and the other operators may
incur substantial costs and experience delays in order to maintain compliance with these existing laws and regulations, which could decrease the cash distributions to the Trust unitholders. In addition, the costs of compliance may increase or the
operations of the underlying properties may be otherwise adversely affected if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to such operations. Such costs could have a material adverse
effect on the cash distributions to the Trust unitholders.
The operations of the underlying properties are
subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production of, oil and natural gas. Failure to comply with
such laws and regulations, as interpreted and enforced, could have a material adverse effect on the cash distributions to the Trust unitholders.
Climate change legislation or regulations restricting emissions of greenhouse gasses could result in increased operating costs and reduced demand for oil and gas which could reduce the
amount of cash available for distribution to Trust unitholders.
On December 15, 2009, the EPA
published its findings that emissions of carbon dioxide, methane, and other 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 adopted regulations that restrict emissions of GHG under existing provisions of the federal CAA, including one rule that limits emissions of GHG from motor vehicles beginning
with the 2012 model year. On June 3, 2010, the EPA also published regulations to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V permitting
programs. On June 26, 2012 the U.S. Circuit Court for the District of Columbia upheld the EPAs GHG regulations; a petition for review by the U.S. Supreme Court has not yet been filed and would be due in April 2013. In November 2010, the
EPA published its final rule expanding its existing GHG monitoring and reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. These requirements became applicable in 2012 for
emissions occurring in 2011, but industry groups have filed suit challenging certain provisions of the rules and are engaged in settlement negotiations to amend and correct the rules. 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
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and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. The final cap-and-trade system
began on January 1, 2012 and legally enforceable compliance obligations began with 2013 emissions. 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 that could adversely affect demand for the oil and natural gas produced.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts,
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, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs
and additional operating restrictions or delays as well as adversely affecting Whitings services.
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 issued guidance, which was
published in the Federal Register on February 12, 2014, for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel.
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 a draft of the report in late 2014 with a final peer-reviewed report expected in 2016. 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 for shale gas in 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, the U.S. Government Accountability Office and the White House Council for Environmental Quality. The U.S. Department of the Interior released a draft
proposed rule in May 2012 governing hydraulic fracturing on federal and Indian oil and natural gas leases to require disclosure of information regarding the chemicals used in hydraulic fracturing, advance approval for well-stimulation activities,
mechanical integrity testing of casing and monitoring of well-stimulation operations, and on May 24, 2013 the Federal Bureau of Land Management issued a revised draft of the proposed rule. On November 20, 2013, the U.S. House of
Representatives passed the Protecting States Rights to Promote American Energy Security Act, which would ban the U.S. Department of the Interior from regulating hydraulic fracturing if enacted into law. In addition, legislation has been
introduced in Congress from time to time to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Also, some states have adopted, and other states are considering adopting,
regulations that
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could restrict or impose additional requirements on activities 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 in Texas) and the public. Such federal or state legislation
could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could
make it easier for third parties opposing hydraulic fracturing to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the
environment including groundwater. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting
delays, litigation risk and potential increases in costs. Further, local governments may seek to adopt, and some have adopted, ordinances within their jurisdictions restricting the use of or regulating the time, place and manner of drilling or
hydraulic fracturing. No assurance can be given as to whether or not similar measures might be considered or implemented in the jurisdictions in which the underlying properties are located. If new laws, regulations or ordinances that significantly
restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in the states or local municipalities where the underlying properties are located, such legal requirements could 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.
The Trust units may lose value as a result of title deficiencies with respect to the underlying properties.
The existence of a material title deficiency with respect to the underlying properties could reduce the value of a
property or render it worthless, thus adversely affecting the NPI and distributions to Trust unitholders. Whiting does not obtain title insurance covering mineral leaseholds, and Whitings failure to cure any title defects may cause Whiting to
lose its rights to production from the underlying properties. In the event of any such material title problem, proceeds available for distribution to Trust unitholders and the value of the Trust units may be reduced.
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
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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 60% of the underlying properties based on the December 31, 2013 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 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
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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.
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 Trust
allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record ownership of the Trust units on the quarterly record date, instead of on the basis of the date a particular Trust
unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the Trust unitholders.
The Trust generally allocates its items of income, gain, loss and deduction between transferors and transferees of the
Trust units based upon the record ownership of the Trust units on the quarterly record date,
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instead of on the basis of the date a particular Trust unit is transferred. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of
the Trust should be determined and allocated on a daily, prorated or other basis, which could require adjustments to the tax returns of the Trust unitholders affected by the issue and result in an increase in the administrative expense of the Trust
in subsequent periods.
The tax treatment of an investment in Trust units could be affected by future legislative,
judicial or administrative changes and differing opinions, possibly on a retroactive basis.
The U.S.
federal income tax treatment of an investment in the Trust may be modified by administrative or legislative changes, or by judicial interpretation, at any time, possibly on a retroactive basis.
Trust unitholders will be required to pay taxes on their share of the 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.
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Unresolved Staff Comments
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None.
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 3,062 gross (351.6
net) producing oil and natural gas wells located in 166 fields on 206,919 gross (72,033 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, 2013, the net production attributable to the underlying properties was 1,133 MBOE or 3.1 MBOE/d. Whiting operates approximately 60% of the underlying properties based on the December 31, 2013
standardized measure of discounted future net cash flows.
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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, 2013, on a
cumulative accrual basis 7.12 MMBOE (87%) 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 March 31, 2015 based on the
Trusts year-end 2013 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.
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, oil and natural gas production attributable to the underlying properties are expected to decline at an estimated annualized rate of 12.6%
from 2014 through the estimated March 31, 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.
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Reserves
As of December 31, 2013, 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, 2013 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, 2013) attributable to i) the Trust based on the term of its NPI, and ii) the underlying properties on a full economic life basis (dollars in thousands):
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Whiting USA Trust
I
(2)
(90% NPI through March 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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725
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2,190
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1,090
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6,661
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15,496
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9,244
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Undeveloped
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Total proved December 31, 2013
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725
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2,190
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1,090
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6,661
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15,496
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9,244
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Standardized measure
(1)
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$
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37,152
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$
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166,853
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(1)
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Standardized measure of discounted future net cash flows as of December 31, 2013. 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, 2013 on a 90% basis were 1,090 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, 2013 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, 2013. 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
-42-
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, 2011 to December 31,
2013, 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 2013, revisions to previous estimates decreased proved reserves by a net amount of 36 MBOE. Included in these revisions were 118 MBbl of downward adjustments to crude oil reserves, primarily due to
reservoir analysis and well performance. This downward revision in crude oil reserves was partially offset by 0.5 Bcf of upward adjustments to natural gas reserves, primarily due to higher gas prices of $3.72 per Mcf in reserve estimates at
December 31, 2013, as compared to gas prices of $3.07 per Mcf at December 31, 2012.
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 (1992) 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 29 years of experience, the majority of which has involved
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reservoir engineering and reserve estimation, and he holds a Bachelors degree in petroleum engineering from the Colorado School of Mines. He is also a member of the Society of Petroleum
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 March 31, 2015, which differs from the June 30, 2015 projected date in the December 31, 2012 reserve report. The projected time to produce the remaining reserves attributable to the Trust
has therefore been slightly accelerated. 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, 2013. Undeveloped acreage is not significant.
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Region
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Number of
Fields
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Total Acreage
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Gross
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Net
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Rocky Mountains
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61
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73,468
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28,016
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Mid-Continent
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56
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67,403
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31,174
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Permian Basin
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28
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31,237
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7,869
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Gulf Coast
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21
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34,811
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4,974
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Total
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166
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206,919
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72,033
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The following is a summary of the producing wells on the underlying properties as of
December 31, 2013:
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Operated Wells
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Non-Operated Wells
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Total Wells
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Oil
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255
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160.1
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2,119
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84.5
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2,374
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244.6
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Natural gas
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67
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46.3
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621
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60.7
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688
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107.0
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Total
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322
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206.4
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2,740
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145.2
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3,062
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351.6
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-44-
The following is a summary of the number of developmental wells drilled on
the underlying properties during the last three years. A dry well is an exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. A
productive well is an exploratory, development or extension well that is not a dry well. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number
of productive wells drilled and quantities of reserves found. Whiting did not drill any exploratory wells on the underlying properties during the periods presented. There were two wells that were in the process of being drilled as of
December 31, 2013.
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Year Ended December 31,
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2013
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2012
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2011
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Productive
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Oil wells
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16
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1.1
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5
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0.5
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7
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1.0
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Natural gas wells
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1
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3
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6
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0.2
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Dry
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2
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0.5
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Total
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17
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1.1
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8
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0.5
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15
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1.7
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Oil and Natural Gas Production
The table below shows total oil and gas production, average sales prices and average production costs attributable to
underlying properties. Sales volumes for natural gas liquids are included with oil sales since they were not material.
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Year Ended December 31,
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2013
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2012
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2011
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Net sales volumes:
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Oil production (MBbl)
(1)
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707
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753
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740
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Natural gas production (MMcf)
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2,553
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2,705
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2,778
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Total production (MBOE)
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1,133
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1,204
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1,203
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Average daily production (MBOE/d)
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3.1
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3.3
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3.3
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Magnolia field sales volumes:
(2)
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Oil production (MBbl)
(1)
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111
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120
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128
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Natural gas production (MMcf)
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149
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167
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165
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Total production (MBOE)
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136
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147
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156
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Average sales prices:
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Oil (per Bbl)
(1)
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$
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83.86
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$
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79.33
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$
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82.63
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Natural gas (per Mcf)
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$
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3.62
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$
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2.86
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$
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4.17
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Production costs per BOE
(3)
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$
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25.50
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$
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24.01
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$
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20.11
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(1)
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Oil includes natural gas liquids.
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(2)
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Magnolia field was the only field that contained 15% or more of the total proved reserve volumes at December 31, 2013.
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-45-
(3)
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Production costs reported above exclude from lease operating expenses ad valorem taxes of $0.9 million ($0.82/BOE), $1.1 million ($0.94/BOE) and
$1.1 million ($0.88/BOE) for the years ended December 31, 2013, 2012 and 2011, respectively.
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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 647 BOE/d during 2013 or 21%
of 2013 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
Other than the underlying
properties commitment of 9.11 MMBOE to the Trust pursuant to the terms of the NPI, neither the Trust nor the underlying properties are committed to deliver fixed quantities of oil or 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, 2013, approximately 60% of these properties were operated by Whiting. Based on annual 2013 production attributable
to the underlying properties, approximately 62% of production was crude oil and natural gas liquids and 38% of production was natural gas. These properties are located in mature fields and have established production profiles. However, production
and distributions to the Trust will continue to decline over time.
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 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, 2013, the net production
attributable to the underlying properties in the region was 412.1 MBOE or 1.1 MBOE/d.
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 24 of
-46-
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, 2013, the net production attributable to the underlying properties in the region was 438.4 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, 2013, the net production
attributable to the underlying properties in the region was 165.9 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, 2013, the net production attributable to the underlying properties in the region was 116.6 MBOE or 0.3
MBOE/d.
Abandonment and Sale of Underlying Properties
Any operator of the underlying properties, including Whiting, has the right to abandon its interest in any well or
property comprising a portion of the underlying properties if, in its opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities. To reduce 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, 2013, 2012 and 2011,
there were 34, 9 and 8 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 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
-47-
distributable to Trust unitholders in the quarter in which they are received. During 2013, Whiting divested two Trust properties which had no associated proved reserves or sales proceeds. Whiting
includes all proceeds from Trust property divestitures, if any, 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:
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royalties, overriding royalties and other burdens, express and implied, under oil and natural gas leases;
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overriding royalties, production payments and similar interests and other burdens created by Whiting or its predecessors in title;
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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;
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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;
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pooling, unitization and communitization agreements, declarations and orders;
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easements, restrictions, rights-of-way and other matters that commonly affect property;
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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
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rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the underlying properties and the NPI
therein.
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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.
-48-
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.
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Legal Proceedings
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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.
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Mine Safety Disclosures
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Not applicable.
-49-
P A R T II
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.
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WHITING USA TRUST I
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By:
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THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.
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By:
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/
S
/ MIKE ULRICH
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Mike Ulrich
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Vice President
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March 12, 2014
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.
-87-
Appendix 1
Cawley, Gillespie & Associates, Inc.
PETROLEUM CONSULTANTS
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13640 BRIARWICK DRIVE,
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306 WEST SEVENTH STREET,
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1000 LOUISIANA STREET,
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SUITE 100 AUSTIN,
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SUITE 302 FORT WORTH,
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SUITE 625 HOUSTON,
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TEXAS 78729-1707
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TEXAS 76102-4987
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TEXAS 77002-5008
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512-249-7000
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817-336-2461
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713-651-9944
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www.cgaus.com
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January 21, 2014
Whiting USA Trust I
1700 Broadway, Suite 2300
Denver, Colorado 80290-2300
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Re:
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Evaluation Summary SEC Price
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Whiting USA Trust I Underlying Properties
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Proved Producing Reserves
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Certain Properties Located in Various States
As of December 31, 2013
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Pursuant to the Guidelines of the Securities and
Exchange Commission for Reporting Corporate
Reserves and Future Net
Revenue
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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 March 31, 2015, which is the estimated date of termination for Whiting USA Trust I. This report,
completed January 21, 2014 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:
A-1
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Proved Developed Producing
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Underlying
Properties
Full Economic Life
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Underlying Properties
Reserves Estimated to be Produced
By March 31,
2015
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Net Reserves
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Oil
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- Mbbl
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6,394.7
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734.1
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Gas
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- MMcf
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15,496.4
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2,433.3
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NGL
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- Mbbl
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266.1
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71.9
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Equivalent*
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- Mbbl
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9,243.5
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1,211.5
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Revenue
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Oil
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- M$
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566,584.2
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65,443.5
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Gas
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- M$
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58,307.7
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9,044.1
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NGL
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- M$
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9,819.1
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2,584.5
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Severance Taxes
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- M$
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48,510.6
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6,029.0
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Ad Valorem Taxes
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- M$
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8,885.6
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975.6
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Operating Expenses
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- M$
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287,969.0
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26,374.0
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Investments
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- M$
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0.0
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0.0
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Net Operating Income
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- M$
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289,345.7
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43,693.4
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Discounted @ 10%
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- M$
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166,852.9
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41,280.0
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*
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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.
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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 $96.78 per bbl and $3.67 per
MMBtu, respectively, were adjusted individually to WTI posted pricing at $93.55 per bbl and Houston Ship Channel pricing at $3.65 per MMBtu, as of December 31, 2013. 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 $88.60 per bbl of oil, $36.91 per bbl of natural gas liquids and $3.76 per mcf of natural gas. For the proved producing reserves of the underlying properties estimated to be produced by March 31, 2015, the average adjusted
prices were $89.15 per bbl of oil, $35.95 per bbl of natural gas liquids and $3.72 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.
A-2
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 costs of plugging and abandonment, less proceeds from the salvage value of equipment and/or facilities, have been included where material.
The reserve estimates were based on interpretations of factual data furnished by your office. We have used all methods and procedures as we considered necessary under the circumstances to prepare the
report. We believe that the assumptions, data, methods and procedures were appropriate for the purpose served by this report. Production data, gas prices, gas price differentials, expense data, tax values and ownership interests were also supplied
by you and were accepted as furnished. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing
has come to our attention, however, that would cause us to believe that we are not justified in relying on such data.
The professional qualifications of the undersigned, the technical person primarily responsible for the preparation of this report, are included as an attachment to this letter.
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Yours very truly,
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/s/ Robert D. Ravnaas
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Robert D. Ravnaas, P.E.
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President
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Cawley, Gillespie & Associates
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Texas Registered Engineering Firm F-693
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A-3
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
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(Columns)
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(1)(11)(21)
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Calendar
or
Fiscal
years/months commencing on effective date.
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(2)(3)(4)
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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.
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(5)(6)(7)
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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.
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(8)
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Average (volume weighted)
gross liquid price
per barrel before deducting production-severance taxes.
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(9)
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Average (volume weighted)
gross gas price
per Mcf before deducting production-severance taxes.
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(10)
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Average (volume weighted)
gross NGL price
per barrel before deducting production-severance taxes.
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(12)
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Revenue
derived from oil sales column (5) times column (8).
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(13)
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Revenue
derived from gas sales column (6) times column (9).
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(14)
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Revenue
derived from NGL sales column (7) times column (10).
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(15)
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Revenue
derived from other sources.
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(16)
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Revenue
derived from hedge positions.
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(17)
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Total Revenue
sum of column (12) through column (16).
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(18)
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Production-Severance taxes
deducted from gross oil and NGL revenue.
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(19)
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Production-Severance taxes
deducted from gross gas revenue.
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(20)
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Revenue after taxes
column (17) less column (18) and column (19).
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Cawley, Gillespie & Associates, Inc.
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Appendix
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Page 1
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(Columns)
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(22)
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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.
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(23)
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Ad Valorem taxes
.
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(24)
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Work-over Expenses
are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump
repair.
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(25)
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3rd Party COPAS
are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
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(26)
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Other Deductions
may include compression-gathering expenses, transportation costs and water disposal costs.
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(27)
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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.
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(28)(29)
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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.
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(30)
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Cumulative Discounted Cash Flow
is calculated by discounting monthly cash flows at the specified annual rates.
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MISCELLANEOUS
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Input Data
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Evaluation parameters such as rates, tax percentages, and expenses are shown below columns (21-26).
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Interests
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Initial and final expense and revenue interests are shown below columns (27-28).
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DCF Profile
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The cash flow discounted at six different rates are shown at the bottom of columns (29-30). Interest has been compounded monthly.
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Life
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The economic life of the appraised property is noted in the lower right-hand corner of the table.
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Footnotes
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Well ID information or other pertinent comments may be shown in the lower left-hand footnotes.
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Cawley, Gillespie & Associates, Inc.
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Appendix
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Page 2
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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
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Cawley, Gillespie & Associates, Inc.
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Appendix
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Page 3
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method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy
that is directly related to the complexity of the reservoir and the quality and quantity of data available.
Volumetric
. This method employs analyses of physical measurements of rock and fluid properties to calculate
the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are
not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of
the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy
can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.
Analogy
. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The
analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of
accuracy.
Much of the information used in the estimation of reserves is itself arrived at by the use of
estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained
about well and reservoir performance.
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Cawley, Gillespie & Associates, Inc.
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Appendix
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Page 4
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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:
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(22)
Proved
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oil and gas reserves
. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to
the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the
hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
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(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
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Cawley, Gillespie & Associates, Inc.
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Appendix
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Page 5
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date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by
contractual arrangements, excluding escalations based upon future conditions.
(6)
Developed oil and gas reserves
. Developed oil and gas reserves are
reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating
methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(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
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Cawley, Gillespie & Associates, Inc.
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Appendix
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Page 6
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or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication
with the proved reservoir.
(iii) Probable reserves
estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv) See also guidelines in paragraphs (17)(iv) and
(17)(vi) of this section (below).
(17)
Possible reserves
.
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i) When deterministic methods are used, the total quantities
ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will
equal or exceed the proved plus probable plus possible reserves estimates.
(ii) Possible reserves may be assigned to areas of a reservoir
adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits
of commercial production from the reservoir by a defined project.
(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.
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Appendix
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Page 7
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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.
(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).
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Cawley, Gillespie & Associates, Inc.
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Appendix
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Page 8
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Cawley, Gillespie & Associates, Inc.
PETROLEUM CONSULTANTS
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13640 BRIARWICK DRIVE,
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306 WEST SEVENTH STREET,
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1000 LOUISIANA STREET,
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SUITE100 AUSTIN,
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SUITE 302 FORT WORTH,
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SUITE 625 HOUSTON,
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TEXAS 78729-1707
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TEXAS 76102-4987
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TEXAS 77002-5008
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512-249-7000
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817-336-2461
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713-651-9944
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www.cgaus.com
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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.