MV Oil Trust - Annual Report: 2011 (Form 10-K)

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PART IV

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

Commission File Number 1-33219

MV OIL TRUST
(Exact name of registrant as specified in its charter)

Registrant's telephone number, including area code: (855) 802-1094

         Securities registered pursuant to Section 12(b) of the Act:

         Securities registered pursuant to Section 12(g) of the Act: None

         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o    No ý.

         Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý.

         Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

         Indicate by checkmark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o    No o

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

         Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o    No ý

         The aggregate market value of the 8,625,000 Units of Beneficial Interest in MV Oil Trust held by non-affiliates of the registrant, computed using the closing sales price of $41.84 on June 30, 2011, was approximately $360,870,000.

         Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. As of March 12, 2012, 11,500,000 Units of Beneficial Interest in MV Oil Trust were outstanding.

Documents Incorporated By Reference: None

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FORWARD-LOOKING STATEMENTS

        This Annual Report on Form 10-K, which we refer to as the "Form 10-K," contains forward-looking statements about MV Partners, LLC, which we refer to herein as "MV Partners," and MV Oil Trust, which we refer to herein as the "trust," that are subject to risks and uncertainties and that are intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities Exchange Act of 1934, as amended, which we refer to as the "Exchange Act". All statements other than statements of historical fact included in this document, including, without limitation, statements under "Business" and "Risk Factors" regarding the financial position, business strategy, production and reserve growth, and other plans and objectives for the future operations of MV Partners and the trust, are forward-looking statements. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Forward-looking statements are subject to risks and uncertainties and include statements pertaining to future development activities and costs and other statements in this Form 10-K that are prospective and constitute forward-looking statements.

        When used in this document, the words "believes," "expects," "anticipates," "intends" or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this Form 10-K, could affect the future results of the energy industry in general, and MV Partners and the trust in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:

•

risks incident to the drilling and operation of oil and natural gas wells;



•

future production and development costs;



•

the effect of existing and future laws and regulatory actions;



•

the effect of changes in commodity prices and conditions in the capital markets;



•

competition from others in the energy industry;



•

economic uncertainty and the credit markets generally;



•

ability of commodity purchasers to make payment;



•

weather conditions or force majeure events;



•

uncertainty of estimates of oil and natural gas reserves and production; and



•

inflation.

        This Form 10-K describes other important factors that could cause actual results to differ materially from expectations of MV Partners and the trust, including under the heading "Risk Factors." All written and oral forward-looking statements attributable to MV Partners or the trust or persons acting on behalf of MV Partners or the trust are expressly qualified in their entirety by such factors.

GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

        In this Form 10-K the following terms have the meanings specified below.

        Bbl—One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

        Boe—One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals six Mcf of natural gas and one Bbl of crude oil equals 1.54 Bbls of natural gas liquids.

        Btu or British Thermal Unit—The quantity of heat required to raise the temperature of one pound of water one degree Fahrenheit.

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        Developed Acreage—The number of acres that are allocated or assignable to productive wells or wells capable of production.

        Development Well—A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

        Estimated Future Net Revenues—Also referred to as "estimated future net cash flows." The result of applying current prices of oil, natural gas and natural gas liquids to estimated future production from oil, natural gas and natural gas liquids proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves, excluding overhead.

        Field—An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

        Gross Acres or Gross Wells—The total acres or wells, as the case may be, in which a working interest is owned.

        MBbl—One thousand barrels of crude oil or other liquid hydrocarbons.

        MBoe—One thousand barrels of oil equivalent.

        Mcf—One thousand standard cubic feet of natural gas.

        MMBbls—One million barrels of crude oil or other liquid hydrocarbons.

        MMBoe—One million barrels of oil equivalent.

        MMcf—One million standard cubic feet of natural gas.

        Net Acres—The sum of the fractional working interests owned in gross acres.

        Net Profits Interest—A nonoperating interest that creates a share in gross production from an operating or working interest in oil and natural gas properties. The share is measured by net profits from the sale of production after deducting costs associated with that production.

        Net Revenue Interest—An interest in all oil, natural gas and natural gas liquids produced and saved from, or attributable to, a particular property, net of all royalties, overriding royalties, net profits interests, carried interests, reversionary interests and any other burdens to which the person's interest is subject.

        NGLs—Natural gas liquids.

        Plugging and Abandonment—Activities to remove production equipment and seal off a well at the end of a well's economic life.

        Proved Developed Non-Producing Reserves—Proved developed reserves expected to be recovered from zones behind casing in existing wells.

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        Proved Developed Oil and Gas Reserves—Proved Oil and Gas Reserves that can be expected to be recovered:

(A)

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



(B)

through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

        Proved Developed Producing Reserves—Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production to market.

        Proved Oil and Gas Reserves—Those quantities of oil and gas that, 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.

(A)

The area of a reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) 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.



(B)

In the absence of data on fluid contacts, proved quantities in the reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.



(C)

Where direct observation from well penetrations has defined a highest known oil 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.



(D)

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) 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 (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.



(E)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is determined. The price is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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        Proved Undeveloped Oil and Gas Reserves—Proved Oil and Gas Reserves 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.

(A)

Reserves on undrilled acreage are 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.



(B)

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.



(C)

Under no circumstances are estimates for undeveloped reserves to 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 or by other evidence using reliable technology establishing reasonable certainty.

        Recompletion—The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

        Reservoir—A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

        Standardized Measure of Discounted Future Net Cash Flows—Also referred to herein as "standardized measure." It is the present value of estimated future net revenues computed by discounting estimated future net revenues at a rate of 10% annually.

        The Financial Accounting Standards Board requires disclosure of standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities per accounting literature for extractive activities—oil and gas, as follows: A standardized measure of discounted future net cash flows relating to an enterprise's interests in (a) proved oil and gas reserves and (b) oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the enterprise participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves shall be disclosed as of the end of the year. The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. The following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed:

        a.     Future cash inflows.    These shall be computed by the average of the first-day-of-the-month prices during the 12-month period preceding the end of the year for 2009, 2010 and 2011 of oil and gas relating to the enterprise's proved reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

        b.     Future development and production costs.    These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

        c.     Future income tax expenses.    These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to

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the future pretax net cash flows relating to the enterprise's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions, tax credits and allowances relating to the enterprise's proved oil and gas reserves.

        d.     Future net cash flows.    These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

        e.     Discount.    This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

        f.      Standardized measure of discounted future net cash flows.    This amount is the future net cash flows less the computed discount.

        Working Interest—Also called an operating interest. The right granted to the lessee of a property to explore for and to produce and own oil, gas or other minerals. The working interest owner bears the exploration, development and operating costs on either a cash, penalty or carried basis.

        Workover—Operations on a producing well to restore or increase production.

PART I

Item 1.    Business.

General

        MV Oil Trust, which we refer to as the "trust," was formed in August 2006, by MV Partners, LLC, which we refer to as "MV Partners." Much of the information disclosed herein has been provided to the trust by MV Partners, including information associated with the underlying properties such as production and well counts, major producing areas, customer relationships, competition, marketing and post-production services, and certain information on which reserve data is based.

        The trust is a statutory trust created under the Delaware Statutory Trust Act. The business and affairs of the trust are managed by The Bank of New York Mellon Trust Company, N.A., as trustee. The trust maintains its offices at the office of the trustee, at 919 Congress Avenue, Austin, Texas 78701. The telephone number of the trustee is 1-855-802-1094. In addition, Wilmington Trust Company acts as the Delaware trustee of the trust. The Delaware trustee has only minimal rights and duties as are necessary to satisfy the requirements of the Delaware Statutory Trust Act. The trust does not have any employees, and the business and affairs of the trust are managed by The Bank of New York Mellon Trust Company, N.A., as trustee.

        The trustee does not maintain a website for filings by the trust with the Securities and Exchange Commission, which we refer to as the "SEC." Electronic filings by the trust with the SEC are available free of charge through the SEC's website at www.sec.gov and at www.businesswire.com/cnn/mvo.htm.

        As of December 31, 2006, the trust had no assets other than $1,000 cash and had conducted no operations other than in connection with the initial public offering of the units of beneficial interest in the trust, which are referred to herein as the "trust units." On January 24, 2007, MV Partners and the trust completed the initial public offering of trust units. In connection with the completion of the initial public offering of trust units, on January 24, 2007, MV Partners conveyed a term net profits interest to the trust that represents the right to receive 80% of the net proceeds (calculated as described below) from all of MV Partners' interests in oil and natural gas properties as of January 24, 2007, which is referred to herein as the "net profits interest." These properties are located in the Mid-Continent region in the States of Kansas and Colorado. MV Partners' net interests in such properties, after deduction of all royalties and other burdens on production thereon as of January 24, 2007, is referred to herein as the "underlying properties." As of December 31, 2011, the underlying properties produced predominantly oil from approximately 1,000 wells, and the projected reserve life of the underlying

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properties was in excess of 50 years. Based on the summary prepared by Cawley, Gillespie & Associates, Inc., independent petroleum and geological engineers, which we refer to as "CG&A", of its reserve report as of December 31, 2011 for the trust, which is summarized herein under "—Description of the Underlying Properties—Reserves" and is referred to herein as the "reserve report," the net profits interest would entitle the trust to receive net proceeds from the sale of production of not less than 11.5 MMBoe of proved reserves during the term of the trust, calculated as 80% of the proved reserves attributable to the underlying properties expected to be produced during the term of the trust. Of these reserves, approximately 87% were classified as proved developed producing reserves as of December 31, 2011. Production from the underlying properties for the year ended December 31, 2011 was approximately 98% oil and approximately 2% natural gas and natural gas liquids. The underlying properties are all located in mature fields that are characterized by long production histories and numerous additional development opportunities to help reduce the natural decline in production from the underlying properties.

        The net profits interest will terminate on the later to occur of (1) June 30, 2026, or (2) the time when 14.4 MMBoe have been produced from the underlying properties and sold (which amount is the equivalent of 11.5 MMBoe in respect of the trust's right to receive 80% of the net proceeds from the underlying properties pursuant to the net profits interest). As of December 31, 2011, cumulatively, since inception, the Trust has received payment for approximately 4.0 MMBoe of the trust's 11.5 MMBoe interest. The gross proceeds used to calculate the net profits interest is based on prices realized for oil, natural gas and natural gas liquids attributable to the underlying properties for each calendar quarter during the term of the net profits interest. MV Partners deducts from the gross proceeds all hedge payments made by MV Partners to hedge contract counterparties upon monthly settlements of existing hedge contracts and derivatives to which MV Partners was a party as of January 24, 2007, which is referred to herein as the "hedge contracts." The last hedge contract expired in December 2010. In addition, in connection with the conveyance of the net profits interest, on January 24, 2007, MV Partners also assigned to the trust the right to receive 80% of all amounts payable to MV Partners from hedge contract counterparties upon monthly settlements of the hedge contracts. In calculating the net proceeds used to calculate the net profits interest, MV Partners deducts from the gross proceeds from the underlying properties all lease operating expenses, maintenance expenses and capital expenditures (including the cost of workovers and recompletions, drilling costs and development costs), amounts that may be reserved for future capital expenditures (which reserve amounts may not exceed $1.0 million in the aggregate at any given time), post-production costs and production and property taxes paid by MV Partners.

        Net proceeds payable to the trust depend upon production quantities, sales prices of oil, natural gas and natural gas liquids, and costs to develop and produce the oil, natural gas and natural gas liquids. 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 amount of those excess costs, plus interest at the prime rate.

        The trust will make quarterly cash distributions of substantially all of its quarterly cash receipts, after deduction of fees and expenses for the administration of the trust, to holders of its trust units during the term of the trust. The trust's first quarterly distribution consisted of an amount in cash paid by MV Partners equal to the amount that would have been payable to the trust had the net profits interest been in effect during the period from July 1, 2006 through December 31, 2006. Furthermore, the cash payment included 80% of all amounts paid to MV Partners from hedge contract counterparties for settlements related to the period from July 1, 2006 through December 31, 2006. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the underlying properties diminishing over time, a portion of each distribution will represent a return of the original investment in the trust units.

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        The trust was created to acquire and hold the net profits interest for the benefit of the trust unitholders. The net profits interest is passive in nature and neither the trust nor the trustee has any control over or responsibility for costs relating to the operation of the underlying properties. The business and affairs of the trust are managed by the trustee, and MV Partners and its affiliates have no ability to manage or influence the operations of the trust. The underlying properties, for which MV Partners is designated as the operator, are currently operated on a contract operator basis by Vess Oil Corporation, which we refer to as "Vess Oil," and Murfin Drilling Company, Inc., which we refer to as "Murfin Drilling," each of which is an affiliate of MV Energy, LLC, which we refer to as "MV Energy," the sole manager of MV Partners. MV Partners does not as a matter of course make public projections as to future sales, earnings or other results relating to the underlying properties.

Description of the Trust Units

        Each trust unit is a unit of the 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 trust units as every other trust unitholder has regarding his units. The trust units are in book-entry form only and are not represented by certificates. The trust had 11,500,000 trust units outstanding as of March 12, 2012.

Distributions and Income Computations

        Each quarter, the trustee will determine the amount of funds available for distribution to the trust unitholders. Available funds are the excess cash, if any, received by the trust from the net profits interest, payments from the hedge contracts and other sources (such as interest earned on any amounts reserved by the trustee) in that quarter, over the trust's expenses for that quarter. Available funds will be reduced by any cash the trustee decides to hold as a reserve against future expenses. It is expected that quarterly cash distributions during the term of the trust will be made by the trustee on or before the 25^th day of the month following the end of each quarter to the trust unitholders of record on the 15^th day of the month following the end of each quarter (or the next succeeding business day).

        Unless otherwise advised by counsel or the Internal Revenue Service, which we refer to herein as the "IRS," the trustee will treat the income and expenses of the trust for each quarter as belonging to the trust unitholders of record on the quarterly record date. For federal income tax purposes, trust unitholders must take into account items of income, gain, loss, deduction and credit consistent with their methods of accounting and without regard to the taxable year or accounting method employed by the trust and without regard to the quarter the trust makes distributions related to those items to the trust unitholders. Variances between taxable income and cash distributions may occur. For example, the trustee could establish a reserve in one quarter using funds that would be included in income in the quarter in which the reserve is created but may not result in a tax deduction or a distribution until a later quarter or possibly in a later taxable year. Similarly, the trustee could also make a payment in one quarter that would be amortized for income tax purposes over several quarters. See "—Federal Income Tax Matters."

Periodic Reports

        The trustee files all required trust federal and state income tax and information returns. The trustee prepares and provides the tax information that trust unitholders need to correctly report their share of the income and deductions of the trust. The trustee also causes to be prepared and filed reports required to be filed under the Exchange Act and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading, and also causes the trust to comply with the provisions of The Sarbanes-Oxley Act of 2002, including but not limited to, by establishing, evaluating and maintaining a system of internal controls over financial reporting in compliance with the requirements of Section 404 thereof.

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        Each trust unitholder and his 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 will 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 of trust unitholders. 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. The affirmative vote of the holders of a majority of the outstanding trust units is required to:

•

dissolve the trust;



•

remove the trustee or the Delaware trustee;



•

amend the trust agreement (except with respect to certain matters that do not adversely affect the rights of trust unitholders in any material respect);



•

merge or consolidate the trust with or into another entity; or



•

approve the sale of all or any material part of the assets of the trust.

        In addition, certain amendments to the trust 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 MV Partners in conjunction with its sale of underlying properties.

Duration of the Trust; Sale of the Net Profits Interest

        The trust will remain in existence until the later to occur of (1) June 30, 2026, or (2) the time when 14.4 MMBoe have been produced from the underlying properties and sold (which amount is the equivalent of 11.5 MMBoe in respect of the trust's right to receive 80% of the net proceeds from the underlying properties pursuant to the net profits interest). The trust will dissolve prior to its termination if:

•

the trust sells the net profits interest;



•

annual gross proceeds attributable to the net profits interest are less than $1 million for each of two consecutive years;



•

the holders of a majority of the outstanding trust units vote in favor of dissolution; or

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•

there is a judicial dissolution of the trust.

        The trustee would then sell all of the trust's 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 the net proceeds are detailed and extensive. The following information summarizes the material information contained in the conveyance related to the computation of the net proceeds. For more detailed provisions concerning the net profits interest, please see the conveyance, which is referenced as an exhibit to this Form 10-K.

Net Profits Interest

        The term net profits interest was conveyed to the trust by MV Partners on January 24, 2007 by means of a conveyance instrument that has been recorded in the appropriate real property records in each county in Kansas and Colorado where the oil and natural gas properties to which the underlying properties relate are located. The net profits interest burdens the net interests owned by MV Partners in the underlying properties in existence as of January 24, 2007.

        The amounts paid to the trust for the net profits interest 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 80% of the aggregate net proceeds attributable to a computation period will be paid to the trust on or before the 25^th day of the month following the computation period. MV Partners will not pay to the trust any interest on the net proceeds held by MV Partners prior to payment to the trust. The trustee will make distributions to trust unitholders quarterly, if sufficient funds are available. See "—Description of the Trust Units—Distributions and Income Computations."

        "Gross proceeds" means:

•

the aggregate amount received by MV Partners 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), less



•

the aggregate amounts paid by MV Partners upon settlement of the hedge contracts on a quarterly basis, as specified in the hedge contracts.

        Gross proceeds does not include consideration for the transfer or sale of any underlying property by MV Partners or any subsequent owner to any new owner unless the net profits interest is released (as is permitted in certain circumstances). Gross proceeds also does not include any amount for oil, natural gas or natural gas liquids lost in production or marketing or used by the owner of the underlying properties in drilling, production and plant operations. Gross proceeds includes payments for future production if they are not subject to repayment in the event of insufficient subsequent production.

        "Net proceeds" means gross proceeds less the following:

•

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;



•

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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•

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;



•

costs paid by an owner of a property comprising the underlying properties under any joint operating agreement;



•

all other costs and expenses, capital costs and liabilities of exploring for, drilling, recompleting, 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 (net of any capital costs for which a reserve had already been made to the extent such capital costs are incurred during the computation period) other than costs and expenses for certain future non-consent operations;



•

costs or charges associated with gathering, treating and processing oil, natural gas and natural gas liquids;



•

any overhead charge incurred pursuant to any operating agreement relating to an underlying property, including the overhead fee payable by MV Partners to Vess Oil and Murfin Drilling as described below;



•

costs paid to counterparties under the hedge contracts or to the persons that provide credit to maintain any hedge contracts, excluding any hedge settlement amounts;



•

amounts previously included in gross proceeds but subsequently paid as a refund, interest or penalty;



•

costs and expenses for renewals or extensions of leases; and



•

at the option of MV Partners (or any subsequent owner of the underlying properties), amounts reserved for approved capital expenditure projects, including well drilling, recompletion and workover costs, which amounts will at no time exceed $1.0 million in the aggregate, and will be subject to the limitations described below.

        During each twelve-month period beginning on the later to occur of (1) June 30, 2023 and (2) the time when 13.2 MMBoe have been produced from the underlying properties and sold (which is the equivalent of 10.6 MMBoe in respect of the net profits interest), which we refer to, in either case, as the "Capital Expenditure Limitation Date", the sum of the capital expenditures and amounts reserved for approved capital expenditure projects for such twelve-month period may not exceed the Average Annual Capital Expenditure Amount. The "Average Annual Capital Expenditure Amount" means the quotient of (x) the sum of the capital expenditures and amounts reserved for approved capital expenditure projects with respect to the three twelve-month periods ending on the Capital Expenditure Limitation Date, divided by (y) three. Commencing on the Capital Expenditure Limitation Date, and each anniversary of the Capital Expenditure Limitation Date thereafter, the Average Annual Capital Expenditure Amount will be increased by 2.5% to account for expected increased costs due to inflation.

        As is customary in the oil and natural gas industry, MV Partners pays an overhead fee to Vess Oil and Murfin Drilling to operate the underlying properties on behalf of MV Partners. The operating activities include various engineering, accounting and administrative functions. The fee is based on a monthly charge per active operated well, which totaled $2.7 million in 2009, $2.8 million in 2010 and $2.8 million in 2011 for all of the underlying properties for which MV Partners was designated as the operator. The fee is adjusted annually 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 prime

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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 receipts and cash disbursements basis.

Hedge Contracts

        Prior to the entry of the conveyance, MV Partners had entered into certain hedge contracts related to the oil production from the underlying properties through the year ended December 31, 2010. MV Partners has not entered into hedge contracts relating to oil volumes expected to be produced after December 31, 2010, and the terms of the conveyance of the net profits interest prohibit MV Partners from entering into new hedging arrangements for the benefit of the trust.

Additional Provisions

        If a controversy arises as to the sales price of any production, then for purposes of determining gross proceeds:

•

amounts withheld or placed in escrow by a purchaser are not considered to be received by the owner of the underlying property until actually collected;



•

amounts received by the owner of the underlying property and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to it by the escrow agent; and



•

amounts received by the owner of the underlying property and not deposited with an escrow agent will be considered to have been received.

        The trustee is not obligated to return any cash received from the net profits interest. Any overpayments made to the trust by MV Partners due to adjustments to prior calculations of net proceeds or otherwise will reduce future amounts payable to the trust until MV Partners recovers the overpayments plus interest at the prime rate.

        The conveyance generally permits MV Partners to transfer without the consent or approval of the trust unitholders all or any part of its interest in the underlying properties, subject to the net profits interest. The trust unitholders are not entitled to any proceeds of a sale or transfer of MV Partners' interest unless the trust is required to sell the net profits interest as to such interest. Following a sale or transfer, the underlying properties will continue to be subject to the net profits interest, and the net proceeds attributable to the transferred property will be calculated as part of the computation of net proceeds described in this Form 10-K.

        In addition, MV Partners may, without the consent of the trust unitholders, require the trust to release the net profits interest 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 net profits interest 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 MV Partners of the relevant underlying properties and are conditioned upon the trust receiving an amount equal to the fair value to the trust of such net profits interest. Any net sales proceeds paid to the trust are distributable to trust unitholders for the quarter in which they are received.

        As the designated operator of a property comprising the underlying properties, MV Partners may enter into farm-out, operating, participation and other similar agreements to develop the property. MV Partners may enter into any of these agreements without the consent or approval of the trustee or any trust unitholder.

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        MV Partners and any transferee of an underlying property will have 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, MV Partners or any transferee of an underlying property is required under the applicable conveyance to act as a reasonably prudent operator in the State of Kansas under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the net profits interest as a burden on such property. Upon termination of the lease, the portion of the net profits interest relating to the abandoned property will be extinguished.

        MV Partners must maintain books and records sufficient to determine the amounts payable for the net profits interest to the trust. Quarterly and annually, MV Partners must deliver to the trustee a statement of the computation of the net proceeds for each computation period. The trustee has the right to inspect and copy the books and records maintained by MV Partners during normal business hours and upon reasonable notice.

Federal Income Tax Matters

        The following is a summary of certain U.S. federal income tax matters that may be relevant to trust unitholders. This summary is based upon current provisions of the Internal Revenue Code of 1986, as amended, which we refer to as the "Code," existing and proposed Treasury regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. No attempt has been made in the following summary to comment on all U.S. federal income tax matters affecting the trust or the trust unitholders.

        The summary is limited to trust unitholders who are individual citizens or residents of the United States. Accordingly, the following summary has limited application to domestic corporations and persons subject to specialized federal income tax treatment such as, without limitation, tax-exempt organizations, regulated investment companies, insurance companies and foreign persons or entities. Each trust unitholder should consult his own tax advisor with respect to his particular circumstances.

        Tax counsel to the trust advised the trust at the time of formation that, for federal income tax purposes, in its opinion the trust will be treated as a grantor trust and not as an unincorporated business entity. No ruling has been or will be requested from the IRS with respect to the federal income tax treatment of the trust, including as to the status of the trust as a grantor trust for such purposes. Thus, no assurance can be provided that the tax treatment of the trust would be sustained by a court if contested by the IRS or another tax authority. The remainder of the discussion below is based on tax counsel's opinion, at the time of formation, that the trust will be classified as a grantor trust for federal income tax purposes. As a grantor trust, the trust will not be subject to federal income tax at the trust level. Rather, each trust unitholder will be considered for federal income tax purposes to own its proportionate share of the trust's 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 will be subject to tax on its proportionate share of the income and gain attributable to the assets of the trust and will be 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 unitholder's tax method of accounting and without regard to the taxable year or accounting method employed by the trust.

        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

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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.

        Tax counsel to the trust also advised the trust at the time of formation that, for federal income tax purposes, based upon representations made by MV Partners regarding the expected economic life of the underlying properties and the expected duration of the net profits interest, in its opinion the net profits interest 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 will treat the net profits interest as indebtedness subject to Treasury regulations applicable to contingent payment debt instruments, and by purchasing trust units, a trust unitholder will agree to be bound by the trust's application of those regulations, including the trust's determination of the rate at which interest will be deemed to accrue on the net profits interest. No assurance can be given that the IRS or another taxing authority will not assert that the net profits interest should be treated differently. Any such different treatment could affect the amount, 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.

        Tax counsel to the trust advised the trust at the time of formation that, for federal income tax purposes, in its opinion the net profits interest should not be integrated with the hedge contracts. Although not definitively addressed by existing authorities, the federal income tax treatment of the net profits interest may be affected by the right to receive payments under the hedge contracts. Specifically, the right to receive payments on the hedge contracts could be integrated with the net profits interest and deemed to be a source other than production for repayment of the net profits interest, which characterization could adversely affect the treatment of the net profits interest as a production payment, and thus a debt instrument, for federal income tax purposes.

Widely Held Fixed Investment Trust Reporting Information

        The trustee assumes that some trust units are held by a middleman, as such term is broadly defined in Treasury regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name). Therefore, the trustee considers the trust to be a non-mortgage widely held fixed investment trust ("WHFIT") for U.S. federal income tax purposes. The Bank of New York Mellon Trust Company, N.A., 919 Congress Avenue, Austin, Texas 78701, telephone number 1-855-802-1094, is the representative of the trust that will provide tax information in accordance with applicable Treasury regulations governing the information reporting requirements of the trust as a WHFIT.

Available Trust Tax Information

        In compliance with the reporting requirements for WHFITs and the dissemination of trust tax reporting information, the trustee provides a generic tax information reporting booklet that is intended to be used only to assist unitholders in the preparation of their 2011 federal and state income tax returns. The projected payment schedule for the net profits interest is included with the tax information booklet. This tax information booklet can be obtained at www.businesswire.com/cnn/mvo.htm.

Description of the Underlying Properties

        The underlying properties consist of MV Partners' net interests in all of its oil and natural gas properties as of January 24, 2007, which properties are located in the Mid-Continent region in the States of Kansas and Colorado. Affiliates of MV Partners are the contract operators of substantially all of the underlying properties.

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        MV Partners' interests in the underlying properties require MV Partners to bear its proportionate share, along with the other working interest owners, of the costs of development and operation of such properties. The underlying properties are burdened by non-working interests owned by third parties, consisting primarily of royalty interests retained by the owners of the land subject to the working interests. These landowners' royalty interests typically entitle the landowner to receive 12.5% of the revenue derived from oil and natural gas production resulting from wells drilled on their land, without any deduction for drilling costs or other costs related to production of oil and natural gas. A working interest percentage represents a working interest owner's proportionate ownership interest in a property in relation to all other working interest owners in that property, whereas a net revenue interest percentage is a working interest owner's percentage of production after reducing such percentage by the percentage of burdens on such production such as royalties and overriding royalties.

        Based on the reserve report, the net profits interest would entitle the trust to receive net proceeds from the sale of production of not less than 11.5 MMBoe of proved reserves attributable to the underlying properties expected to be produced during the term of the net profits interest, calculated as 80% of the proved reserves attributable to the underlying properties expected to be produced during the term of the net profits interest. The reserves attributable to the underlying properties include all reserves expected to be economically produced during the life of the properties, whereas the trust is entitled to only receive 80% 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 net profits interest.

        The Mid-Continent region is a mature producing region with well-known geologic characteristics. Most of the production from the underlying properties consists of desirable crude oil of a quality level between sweet and sour with 33 to 34 gravity averages. Most of the producing wells to which the underlying properties relate are relatively shallow, ranging from 600 to 4,500 feet, and many are completed to multiple producing zones. In general, the producing wells to which the underlying properties relate have stable production profiles and their production is generally long-lived, often with total projected economic lives in excess of 50 years.

Reserves

        The engineering departments of each of Vess Oil and Murfin Drilling, who together manage MV Partners and operate the underlying properties on behalf of MV Partners, maintain oversight and compliance responsibility for the internal reserve estimate process and, in accordance with internal policies and procedures, provide appropriate data to independent third party engineers for the annual estimation of year-end reserves. These engineering departments accumulate historical production data for the underlying properties, calculate historical lease operating expenses and differentials, update working interests and net revenue interests, and obtain logs, 3-D seismic and other geological and geophysical information. This data is forwarded to CG&A, thereby allowing CG&A to prepare estimated proved reserves in their entirety based on such data.

        Estimates of the proved oil and gas reserves attributable to the trust as of December 31, 2009, 2010 and 2011 are based on reports of CG&A. CG&A has been in business since 1961 and serves many organizations and individuals in the petroleum industry, including owners and operators of oil and gas properties, exploration groups, planners, and professionals in investment and finance. One of the principal businesses of CG&A is providing detailed assessment of producing reservoirs. CG&A is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists and does not own an interest in the underlying properties and is not employed on a contingent basis. Mr. W. Todd Brooker, Senior Vice President, is the technical person at CG&A who is primarily responsible for overseeing CG&A's preparation of the reserve estimates. Mr. Brooker is a graduate of the University of Texas at Austin with a Bachelor of Science degree in Petroleum Engineering and has 20 years of experience in petroleum engineering. He is a licensed professional engineer in the State of Texas (License #83462).

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        Oil and gas proved reserves are disclosed by significant geographic area, using the 12-month average beginning-of-month price for the year, based on the use of reliable technologies to estimate proved oil and gas reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Reserve and related information for 2009, 2010 and 2011 is presented consistent with these requirements.

        The discounted estimated future net revenues presented below were prepared using assumptions required by the SEC. Except to the extent otherwise described below, these assumptions include the use of prices for oil, natural gas and natural gas liquids for the reserve report as of December 31, 2011, of $89.09 per Bbl of oil, $3.97 per Mcf of natural gas and $42.33 per Bbl of natural gas liquids, net of pricing differentials, as well as costs for estimated future development and production expenditures to produce the proved reserves as of December 31, 2011. Because oil, natural gas and natural gas liquid prices are influenced by many factors, use of average prices for the reserve report as of December 31, 2011, as required by the SEC, may not be the most accurate basis for estimating future revenues of reserve data. Future net cash flows are discounted at an annual rate of 10%. There is no provision for federal or state income taxes with respect to the future net cash flows attributable to the underlying properties because future net revenues are not subject to taxation at the trust level.

        Proved Reserves of MV Oil Trust.    The following table sets forth, as of December 31, 2011, estimated proved reserves attributable to the trust derived from the reserve report. A summary of the reserve report is included below.

        Information concerning historical changes in net proved reserves attributable to the trust, and the calculation of the standardized measure of discounted future net revenues related thereto, is contained in Note J to the financial statements of the trust included in this Form 10-K. MV Partners has not filed reserve estimates covering the underlying properties with any other federal authority or agency.

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        The following table summarizes the changes in estimated proved reserves of the trust for the periods indicated.

        The reserves above represent the trust's 80% net profits interest in the underlying properties for the remainder of the term of the trust.

        The following table sets forth the estimates of total proved reserves and forecasts of economics attributable to the underlying properties as of December 31, 2011 for the remainder of the term of the trust, as presented in the summary prepared by CG&A of its reserve report as of December 31, 2011 for the trust. The estimates of proved reserves have not been filed with or included in reports to any

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federal authority or agency. The discounted cash flow value shown in the table is not intended to represent the current market value of the trust's estimated oil and natural gas reserves.

        The net profits interest entitles the trust to receive 80% of the net proceeds attributable to MV Partners' interest from the sale of production from the underlying properties. The net profits interest will terminate on the later to occur of (1) June 30, 2026, or (2) the time when 14.4 MMBoe have been produced from the underlying properties and sold, and the trust will soon thereafter wind up its affairs and terminate. For the reserve report, CG&A estimated that the trust would terminate June 30, 2026 based on the calculation that 14.4 MMBoe would have been produced from the underlying properties and sold (which amount is the equivalent of 11.5 MMBoe in respect of the trust's right to receive 80% of the net proceeds from the underlying properties pursuant to the net profits interest) prior to this date.

        Oil and gas prices were adjusted to a WTI Cushing oil price of $96.19 per Bbl and a Henry Hub natural gas price of $4.118 per MMbtu. As specified by the SEC, these prices are 12-month averages based upon the price on the first day of each month during 2011. The price adjustments were based on oil price differentials forecast at -$7.10 per Bbl for all properties. Oil price differentials were not escalated. Gas and NGL price differentials were forecast on a per property basis as provided by MV Partners and were also not escalated. Price differentials include adjustments for transportation and basis differential. Gas prices were further adjusted with a heating value (Btu content) applied on a per-property basis. Operating expenses, workover expenses, COPAS overhead charges and investments were forecast on a per property basis as furnished by MV Partners. Expenses and investments were held constant in accordance with SEC rules and guidelines. Severance tax rates were applied at normal state percentages of oil and gas revenue, except for those Kansas producing properties that are severance tax exempt. Ad valorem taxes of 3.0% of total revenue were applied to each property as provided by MV Partners. Oil and gas conservation tax rates were applied to all Kansas properties at the applicable rates.

        The estimates of proved oil and natural gas reserves attributable to the underlying properties are based on estimates prepared by CG&A. Rules and guidelines established by the SEC regarding the present value of future net revenues were used to prepare these reserve estimates. Oil and natural gas

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reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and estimates of other engineers might differ materially from those included in the report. The accuracy of any reserve estimate is a function of the quality of available data and engineering, and estimates may justify revisions based on the results of drilling, testing, and production activities. Accordingly, reserve estimates are inherently imprecise and should not be construed as representing the actual quantities of future production or cash flows to be realized from oil and natural gas properties or the fair market value of such properties.

Producing Acreage and Well Counts

        For the following data, "gross" refers to the total wells or acres in which MV Partners owns a working interest and "net" refers to gross wells or acres multiplied by the percentage working interest owned by MV Partners. Although many of MV Partners' 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 of Kansas and eastern Colorado. The following is a summary of the approximate acreage of the underlying properties at December 31, 2011.

        The following is a summary of the producing wells on the underlying properties as of December 31, 2011:

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        The following is a summary of the number of developmental wells drilled by MV Partners on the underlying properties during the last three years. MV Partners did not drill any exploratory wells during the periods presented.

        During the years ended December 31, 2009, 2010 and 2011, MV Partners drilled, completed and commenced production with respect to 11, 8 and 8 wells, respectively, on the underlying properties. As of December 31, 2011, no wells were being drilled. Capital expenditures associated with proved undeveloped reserves for the year ended December 31, 2011, were $2.50 million. MV Partners continues to develop further proved undeveloped reserves pursuant to its planned development and workover program. See "Trustee's Discussion and Analysis of Financial Condition and Results of Operations—Planned Development and Workover Program."

        The following table shows the average sales prices per Bbl of oil and Mcf of natural gas produced and the production costs and production and property taxes per Boe for the underlying properties. Sales volumes for natural gas liquids during the periods presented were not significant. Average prices do not include the effect of hedge and other derivative activity.

Major Producing Areas

        Approximately 62% of the net acres included in the underlying properties are located in the El Dorado Area, which is located in southeastern Kansas, and in the Northwest Kansas Area. The underlying properties are all located in mature fields that are characterized by long production histories. The properties provide continual workover and developmental opportunities which MV Partners has pursued to reduce the natural decline in production from the underlying properties.

El Dorado Area

        The underlying properties located in the El Dorado Area are operated on behalf of MV Partners by Vess Oil and are located in the El Dorado, Augusta and the Valley Center Fields. Vess Oil has actively pursued infill drilling, well re-entries, plugback and deepening recompletion operations, various types of restimulation work and equipment optimization programs to reduce the natural decline in production from these fields.

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        El Dorado Field.    The El Dorado Field is located atop the Nemaha Ridge in Central Butler County, Kansas and was first discovered in 1915. Up to 15 horizons have been reported to contain hydrocarbons, ranging from the Admire Sands, at a depth of 650 feet, to the Arbuckle Dolomite, at a depth of 2,500 feet. The primary producing intervals are the Admire, Lansing-Kansas City, Viola, Simpson and Arbuckle. Cumulative production of all producers from the El Dorado Field has exceeded 300 MMBbls of oil with production peaking between 1916 and 1918 at 116,000 Bbls per day in 1918.

        Augusta Field.    The Augusta Field is on a trend similar to the nearby El Dorado Field and strikes northeast parallel to the Nemaha Ridge. The field was first discovered in 1914 and covers approximately 10 square miles of Butler County, Kansas. The primary producing interval has been the Arbuckle with additional production coming from the Simpson and Lansing-Kansas City intervals. Cumulative production of all producers from the Augusta Field has exceeded 48 MMBbls of oil. The Augusta Field is largely an extension of the El Dorado Field and has very similar geological characteristics.

        Vess Oil has maintained constant activity in these fields to increase production. Vess Oil plans to drill additional infill developmental wells in the Arbuckle, Lansing-Kansas City, Simpson and Whitecloud intervals in the El Dorado area during the next five years. Vess Oil also plans to maintain its annual recompletion and workover program over the next five years. Vess Oil has commenced a waterflood program to enhance production from the Whitecloud formation. Vess Oil plans to convert wells as the infill developmental drilling program proceeds.

        Valley Center Field.    The Valley Center Field was first discovered in 1928 and covers approximately 60 square miles of Sedgwick County, Kansas. Production is primarily from the Viola interval, which is located at an average depth of 2,500 feet. Cumulative production of all producers from the Valley Center Field has exceeded 25 MMBbls of oil. The Valley Center Field has similar geological characteristics as the El Dorado Field.

Northwest Kansas Area

        Each of Vess Oil and Murfin Drilling operate leases on behalf of MV Partners included in the underlying properties that are located in the Northwest Kansas Area. The primary fields in this area are the Bemis-Shutts, Trapp, Ray and Hansen Fields. Vess Oil and Murfin Drilling have actively pursued polymer treatments, stimulation workovers and recompletion operations to reduce the natural decline in production from these fields.

        Bemis-Shutts Field.    The Bemis-Shutts Field is located on the Fairport Anticline within the Central Kansas Uplift and was first discovered in 1928. The field consists of 17,080 acres in northeastern Ellis and southeastern Rooks Counties, Kansas. Production has been from multiple pay zones with the primary formation being the Arbuckle interval at a depth of 3,300 feet and the Lansing-Kansas City interval at a depth of 2,800 feet. Cumulative production of all producers from the Bemis-Shutts Field has exceeded 248 MMBbls of oil.

        Both Vess Oil and Murfin Drilling have pursued polymer treatment programs with success in the Bemis-Shutts Field and plan to continue these workovers. MV Partners has continued to acquire 3-D seismic surveys over portions of the field to further define the boundaries of the Arbuckle structure in the field and to evaluate undrilled infill locations. This data is processed as received and currently there are over 17 potential infill drilling locations that have been identified. MV Partners plans to drill these locations over the next five years.

        Trapp Field.    The Trapp Field consists of 35,900 acres in Russell and Barton Counties, Kansas and was first discovered in 1929. Production has primarily been from the Lansing-Kansas City and Shawnee limestones and the Arbuckle dolomite. Cumulative production of all producers from the Trapp Field has exceeded 239 MMBbls of oil.

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        Hansen and Ray Fields.    The Hansen Field is located along the crest of the Stuttgart-Huffstutor Anticline and was first discovered in 1943. Production from this field has primarily come from the Lansing-Kansas City limestone. Cumulative production of all producers from the Hansen Field has exceeded 9.2 MMBbls of oil.

        The Ray Field is located on the eastern flank of the Central Kansas Uplift and was first discovered in 1940. Production has primarily been from the Arbuckle dolomite and the Gorham sands with additional production from the Lansing-Kansas City interval along the eastern flank of the field. Cumulative production of all producers from the Ray Field has exceeded 18 MMBbls of oil.

        The Hansen and Ray Fields consist of over 7,000 acres in Philips and Norton Counties, Kansas.

        Murfin Drilling operates the leases held by MV Partners in the Trapp, Hansen and Ray Fields. Murfin Drilling has informed the trustee that it plans to drill and workover and recomplete additional wells, including acid stimulations, over the next five years.

Marketing and Post-Production Services

        Pursuant to the terms of the conveyance that created the net profits interest, MV Partners 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 that created the net profits interest do not permit MV Partners to charge any marketing fee when determining the net proceeds upon which the net profits interest 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 MV Partners receives for oil, natural gas and natural gas liquid production attributable to MV Partners' remaining interest in the underlying properties.

        Vess Oil and Murfin Drilling, as contract operators, generally sell production from the underlying properties to several purchasers, including MV Purchasing, LLC, which we refer to as "MV Purchasing," under short-term arrangements using market sensitive pricing. MV Purchasing is majority owned by the indirect equity owners of MV Partners. These sales to purchasers are under terms ranging from one month to six months, using market sensitive pricing. Two purchasers, including MV Purchasing, have been purchasing substantially all of the crude oil production, and a substantial portion of the crude oil production may continue be acquired by one or more single purchasers. For the years ended December 31, 2009, 2010 and 2011, MV Purchasing purchased 71%, 72% and 74%, respectively, of the production from the underlying properties. MV Partners does not believe that loss of any of these parties as a purchaser would have a material adverse impact on the business of MV Partners, as substitute purchasers are generally available; however, a purchaser's failure to pay for purchased crude oil could have a significant adverse impact on MV Partners' business.

        Oil production is typically transported by truck from the field to the closest gathering facility or refinery. MV Partners sells the majority of the oil production from the underlying properties under short-term arrangements using market sensitive pricing. The price received by MV Partners for the oil production from the underlying properties is usually based on the NYMEX price applied to equal daily quantities on the month of delivery, which price is then reduced for differentials based upon delivery location and oil quality. The average differential for oil production during the years ended December 31, 2009, 2010 and 2011 were $7.01, $7.10 and $6.91 per barrel, respectively.

        All natural gas produced by MV Partners is marketed and sold to third-party purchasers. The natural gas is sold on a contract basis and, in all but one case, the contracts are in their secondary terms and are on a month-to-month basis. In all cases, the contract price is based on a percentage of a published regional index price, after adjustments for Btu content, transportation and related charges.

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Sale and Abandonment of Underlying Properties

        MV Partners and any transferee of any of the underlying properties will have 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 MV Partners and the trust in determining whether a well is capable of producing in commercially paying quantities, MV Partners is required under the conveyance to act as a reasonably prudent operator in the State of Kansas under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the net profits interest as a burden on such property. For the years ended December 31, 2009, 2010 and 2011, MV Partners plugged and abandoned 16, two and 13 wells, respectively, based on its determination that such wells were no longer economical to operate or restore to production.

        MV Partners generally may sell all or a portion of its interests in the underlying properties, subject to and burdened by the net profits interest, without the consent of the trust unitholders. In addition, MV Partners may, without the consent of the trust unitholders, require the trust to release the net profits interest 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 net profits interest 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 MV Partners of the relevant underlying properties and are conditioned upon the trust receiving an amount equal to the fair value to the trust of such net profits interest. Any net sales proceeds paid to the trust are distributable to trust unitholders for the quarter in which they are received.

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 MV Partners' rights to production and the value of production from the underlying properties, they have been taken into account in calculating the trust's interests and in estimating the size and the value of the reserves attributable to the underlying properties.

        MV Partners' interests in the oil and natural gas underlying properties are typically subject, in one degree or another, to one or more of the following:

•

royalties, overriding royalties and other burdens, express and implied, under oil and natural gas leases;



•

overriding royalties, production payments and similar interests and other burdens created by MV Partners or its predecessors in title;



•

a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the underlying properties or their title;



•

liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;



•

pooling, unitization and communitization agreements, declarations and orders;



•

easements, restrictions, rights-of-way and other matters that commonly affect property;

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•

conventional rights of reassignment that obligate MV Partners to reassign all or part of a property to a third party if MV Partners intends to release or abandon such property; and



•

rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the underlying properties and the net profits interest therein.

        MV Partners has informed the trustee that MV Partners believes that the burdens and obligations affecting the underlying properties are conventional in the industry for similar properties. MV Partners also has informed the trustee that MV Partners 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 net profits interest.

        MV Partners acquired the underlying properties in two transactions, the first of which was in 1998 when it acquired a substantial portion of the underlying properties from a major oil and gas company and the second of which was in 1999 when it acquired the remaining portion of the underlying properties from a large independent oil and gas company. At the time of its acquisition of the underlying properties, MV Partners believes that it undertook a thorough title examination of the underlying properties.

        MV Partners has recorded the conveyance of the net profits interest in Kansas in the real property records in each Kansas county where the properties are located. MV Partners has informed the trustee that MV Partners believes that the delivery and recording of the conveyance constituted fully conveyed and vested property interests in the trust under Kansas law. Although no assurance can be given, MV Partners has informed the trustee that MV Partners believes that, if, during the term of the trust, MV Partners becomes involved as a debtor in a bankruptcy proceeding, the conveyance of the net profits interest, as vested and recorded property interests, cannot be avoided by a bankruptcy trustee. If in such a proceeding a determination were made that the conveyance constitutes an executory contract and the net profits interest is not a fully conveyed property interest under the laws of Kansas, and if such contract were not to be assumed in a bankruptcy proceeding involving MV Partners, the trust would be treated as an unsecured creditor of MV Partners with respect to such net profits interest in the pending bankruptcy proceeding.

        Oil and gas leases are real property interests under Colorado law. Net profits interests are non-operating, non-possessory interests carved out of the oil and gas leasehold estate. MV Partners has informed the trustee that MV Partners believes that it is possible that the net profits interest for the underlying properties located in Colorado may not be treated as a real property interest under the laws of Colorado. MV Partners has recorded the conveyance of the net profits interest in the real property records of Colorado in accordance with local recording acts. MV Partners has informed the trustee that MV Partners believes that, if, during the term of the trust, MV Partners becomes involved as a debtor in a bankruptcy proceeding, the net profits interest relating to the underlying properties located in Colorado should be treated as a fully conveyed personal property interest under the laws of Colorado. In such a proceeding, however, a determination could be made that the conveyance constitutes an executory contract and the net profits interest is not a fully conveyed personal property interest under the laws of Colorado, and if such contract were not to be assumed in a bankruptcy proceeding involving MV Partners, the trust would be treated as an unsecured creditor of MV Partners with respect to such net profits interest in the pending bankruptcy proceeding. Although no assurance can be given, MV Partners does not believe that the conveyance of the net profits interest relating to the underlying properties located in Colorado should be subject to rejection in a bankruptcy proceeding as an executory contract.

Competition and Markets

        The oil and natural gas industry is highly competitive. MV Partners competes with major oil and natural gas companies and independent oil and natural gas companies for oil and natural gas,

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equipment, personnel and markets for the sale of oil and natural gas. Many of these competitors are financially stronger than MV Partners, 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 MV Partners 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 trust's interests and estimated and actual future net revenues to the trust. In view of the many uncertainties that affect the supply and demand for oil and natural gas, neither the trust nor MV Partners 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.

Regulation

        The production of oil and gas from the underlying properties is affected by many state and federal regulations with respect to allowable rates of production, drilling permits, well spacing, marketing, environmental matters and pricing. Future regulations could change allowable rates of production or the manner in which oil and gas operations may be lawfully conducted.

FERC Regulation

        Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or NGPA, and regulations issued under those statutes. Over the last two decades, the FERC has issued orders and adopted regulations resulting in a restructuring of the natural gas industry. The principal elements of this restructuring were the requirement that interstate pipelines separate, or "unbundle," into individual components the various services offered on their systems, with all transportation services to be provided on a non-discriminatory basis, and the prohibition against an interstate pipeline providing gas sales services except through separately organized affiliates. In various rulemaking proceedings following its initial unbundling requirement, the FERC has refined its regulatory program applicable to interstate pipelines in various respects, and it has announced that it will continue to monitor these and other regulations to determine whether further changes are needed. In addition to rulemaking proceedings, the FERC establishes new policies and regulations through policy statements and adjudications of individual pipeline matters. Further, additional changes to regulations may occur based on actions taken by the United States Congress and/or the courts.

        In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

        Sales of crude oil, condensate, and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is subject to rate and access regulation. The FERC regulates interstate oil pipeline

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transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be just and reasonable and may not be unduly discriminatory or confer any undue preference upon any shopper. Rates generally are cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances.

        Although the price at which MV Partners sells oil, natural gas and natural gas liquids is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation, with regard to physical sales of natural gas and oil, MV Partners is required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission, or the CFTC, and the Federal Trade Commission, or FTC. If MV Partners were to violate the anti-market manipulation laws and regulations, MV Partners could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

        As to these various developments, MV Partners has advised the trust that the on-going and evolving nature of these regulatory initiatives makes it impossible to predict their ultimate impact on the prices, markets or terms of sale of natural gas related to the trust.

State and Other Regulation

        In general, the jurisdictions in which royalty properties are located have statutory provisions regulating the production and sale of crude oil and natural gas. The regulations often require permits for the drilling of wells but extend also to the spacing of wells, the prevention of waste of oil and gas resources, the rate of production, prevention and clean-up of pollution and other matters.

Environmental Matters and Regulation

        General.    The operations of the underlying properties are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

•

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;



•

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and



•

require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

        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 underlying properties.

        The following is a summary of the 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, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are

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currently regulated under RCRA's 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. Any such change 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, or CERCLA, also known as the Superfund law, imposes joint and several liability, without regard to fault or 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 a 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. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

        The underlying properties may have been used for oil and natural gas exploration and production for many years. Although MV Partners believes that it has utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, the underlying properties 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 MV Partners' control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, MV Partners could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

        Water Discharges.    The Federal Water Pollution Control Act, or the Clean Water Act, 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 waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

        The Oil Pollution Act of 1990, or the OPA, as amended, which amends the Clean Water Act, imposes strict liability on owners and operators of facilities that are the site of a release of oil into waters of the United States. OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills.

        Air Emissions.    The Federal Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

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        Climate Change.    There has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. Kansas and Colorado have joined Western Climate Initiative, or WCI, a regional organization that is examining measures to reduce greenhouse gas emissions. In 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that greenhouse gases are an "air pollutant" under the federal Clean Air Act and, thus, subject to future regulation. The oil and natural gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact the future operations of the underlying properties. The EPA is moving forward to regulate greenhouse gases. To date, the EPA has issued (i) a "Mandatory Reporting of Greenhouse Gases", or MRR, final rule, effective December 29, 2009, which established a new comprehensive scheme requiring operators of stationary sources in the United States emitting more than established annual thresholds of carbon dioxide-equivalent greenhouse gases to inventory and report their greenhouse gas emissions annually; the Petroleum and Natural Gas Systems Reporting Rule was published on November 30, 2010 and requires certain segments of the industry, including onshore petroleum and natural gas producers, to report carbon dioxide-equivalent greenhouse gases using the same thresholds used in the MRR beginning in 2012; and (iii) an "Endangerment Finding" final rule, effective January 14, 2010, which states that current and projected concentrations of six key greenhouse gases in the atmosphere, as well as emissions from new motor vehicles and new motor vehicle engines, threaten public health and welfare, allowing the EPA to finalize motor vehicle greenhouse gas standards. According to the EPA, the final motor vehicle greenhouse gas standards will trigger construction and operating permit requirements for stationary sources. As a result, the EPA has proposed to tailor these programs such that only large stationary sources will be required to have air permits that authorize greenhouse gas emissions. Laws, regulations, treaties or international agreements related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on the future operations of MV Partners if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on MV Partners' operations. In addition to potential impacts on MV Partners' operations directly or indirectly resulting from climate-change legislation or regulations, MV Partners' operations also could be negatively affected by climate-change related physical changes or changes in weather patterns. At this time, it is not possible to estimate accurately how potential future laws or regulations addressing greenhouse gas emissions would impact the operations of MV Partners.

        The operations of the underlying properties are not adversely impacted by the current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact the operations of the properties.

        OSHA and Other Laws and Regulation.    MV Partners is subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that MV Partners organize and/or disclose information about hazardous materials used or produced in its operations. MV Partners believes that it is in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

        MV Partners believes that it is in substantial compliance 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, MV Partners did not incur any material capital expenditures for remediation or pollution control activities for the years ended December 31, 2009, 2010 and 2011.

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Additionally, MV Partners has informed the trust that MV Partners is not aware of any environmental issues or claims that will require material capital expenditures during 2012. However, there is no assurance that the passage of more stringent laws or regulations in the future will not have a negative impact on the operations of the underlying properties and the cash distributions to the trust unitholders.

Item 1A.    Risk Factors.

The amounts of cash distributions by the trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquid prices.

        The reserves attributable to the underlying properties and the quarterly cash distributions of the trust are highly dependent upon the prices realized from the sale of oil, natural gas and natural gas liquids. Prices of oil, natural gas and natural gas liquids can fluctuate widely on a quarter-to-quarter basis in response to a variety of factors that are beyond the control of the trust and MV Partners. These factors include, among others:

•

political conditions or hostilities in oil and natural gas producing regions, including the Middle East, North Africa and South America;



•

weather conditions or force majeure events;



•

levels of supply of and demand for oil, natural gas and natural gas liquids;



•

U.S. and worldwide economic conditions;



•

the price and availability of alternative fuels;



•

the proximity to, and capacity of, refineries and gathering and transportation facilities; and



•

energy conservation and environmental measures.

        Moreover, government regulations, such as regulation of natural gas gathering and transportation systems and possible price controls, can affect commodity prices in the long term.

        Crude oil prices have been volatile the last several years and in 2011, ranged from a high of $113.93 to a low of $75.67. The NYMEX crude oil spot prices per Bbl were $79.36, $91.38 and $98.83 as of December 31, 2009, 2010 and 2011, respectively. Neither MV Partners nor the trust can predict the timing or the duration of any economic cycle and, depending on the prices realized, the operating results of MV Partners and the financial condition of the trust could be materially and adversely affected.

        Although MV Partners was permitted to, and did enter into, hedge contracts relating to a portion of the oil volumes expected to be produced from the underlying properties, those hedge contracts expired in 2010. MV Partners has not entered into any hedge contracts relating to oil volumes, and the terms of the conveyance of the net profits interest prohibit MV Partners from entering into hedging arrangements for the benefit of the trust. As a result, the amounts of cash distributions by the trust may fluctuate significantly as a result of changes in commodity prices because there will be no hedge contracts in place to reduce the effects of any changes in commodity prices.

        Lower prices of oil, natural gas and natural gas liquids will reduce the amount of the net proceeds to which the trust is entitled and may ultimately reduce the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties. As a result, the operator of any of the underlying properties could determine during periods of low commodity prices to shut in or curtail production from wells on the underlying properties. In addition, the operator of the underlying 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

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higher prices. Because the underlying properties are mature, with many of them being in production since the early 1900s, decreases in commodity prices could have a more significant effect on the economic viability of these properties compared to more recently discovered properties. The commodity price sensitivity of these mature wells is due to a culmination of factors that vary from well-to-well, including the additional costs associated with water handling and disposal, chemicals, surface equipment maintenance, downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result, the volatility of commodity prices may cause the amount of future cash distributions to trust unitholders to fluctuate, and a substantial decline in the price of oil, natural gas or natural gas liquids will reduce the amount of cash available for distribution to the trust unitholders.

Actual reserves and future net revenues may be less than current estimates of proved reserves, which could reduce cash distributions by the trust and the value of the trust units.

        The value of the trust units and the amount of future cash distributions to the trust unitholders will depend upon, among other things, the accuracy of the production and reserves estimated to be attributable to the underlying properties and the net profits interest. Estimating production and reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary both positively and negatively from estimates and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating production and reserves. Those factors and assumptions include:

•

historical production from the area compared with production rates from other producing areas;



•

the assumed effect of governmental regulation; and



•

assumptions about future prices of oil, natural gas and natural gas liquids, production and development expenses, gathering and transportation costs, severance and excise taxes and capital expenditures.

        Changes in these assumptions can materially increase or decrease production and reserve estimates.

        The estimated reserves attributable to the net profits interest and the estimated future net revenues attributable to the net profits interest are based on estimates of reserve quantities and revenues for the underlying properties. See "Item 1. Business—Description of the Underlying Properties—Reserves" for a discussion of the method of allocating proved reserves to the underlying properties and the net profits interest. The quantities of reserves attributable to the underlying properties and the net profits interest 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.

        The revenues of the trust, the value of the trust units and the amount of cash distributions to the trust unitholders depend upon, among other things, the costs incurred by MV Partners to develop and exploit oil and natural gas reserves attributable to the underlying properties. Drilling, production or transportation accidents that temporarily or permanently halt the production and sale of oil, natural gas and natural gas liquids at any of the underlying properties will reduce trust distributions by reducing the amount of net proceeds available for distribution. For example, accidents may occur that result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any costs incurred by MV Partners in connection with any such accidents that are not insured against will have the effect of reducing the net proceeds available for distribution to the trust. In addition, curtailments or damage to pipelines used by MV Partners to transport oil, natural gas and

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natural gas liquid production to markets for sale could reduce the amount of net proceeds available for distribution. Any such curtailment or damage to the gathering systems used by MV Partners could also require MV Partners to find alternative means to transport the oil, natural gas and natural gas liquid production from the underlying properties, which alternative means could require MV Partners to incur additional costs that will have the effect of reducing net proceeds available for distribution by the trust.

Production of oil, natural gas and natural gas liquids on the underlying properties could be materially and adversely affected by severe or unseasonable weather.

        Production of oil, natural gas and natural gas liquids on the underlying properties could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:

•

evacuation of personnel and curtailment of operations;



•

weather-related damage to drilling rigs or other facilities, resulting in suspension of operations;



•

inability to deliver materials to worksites; and



•

weather-related damage to pipelines and other transportation facilities.

The trust and the public trust unitholders have no voting or managerial rights with respect to MV Partners, the operator of the underlying properties. As a result, public trust unitholders have no 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 all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property.

        MV Partners is currently designated as the operator of substantially all of the underlying properties. MV Partners has contracted with two of its affiliates, Vess Oil and Murfin Drilling, to operate these properties on its behalf. Neither the trustee nor the public trust unitholders has any contractual ability to influence or control the field operations of, sale of oil and natural gas from, or future development of, these properties. The public trust unitholders also have no voting rights with respect to MV Partners and, therefore, have no managerial, contractual or other ability to influence MV Partners' or its affiliates' activities as operator of the oil and natural gas properties to which substantially all of the underlying properties relate.

Shortages of oil field equipment, services and qualified personnel available to MV Partners could reduce the amount of cash available for distribution by the trust.

        The demand for qualified and experienced field personnel to drill wells and 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. As part of its development plan for the underlying properties, MV Partners expects to drill 19 development wells and conduct recompletion and workover operations on existing wells included in the underlying properties over the five years ending December 31, 2016. See "Item 7. Trustee's Discussion and Analysis of Financial Condition and Results

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of Operations—Planned Development and Workover Program" for a description of MV Partners' development plans. 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 the ability of MV Partners to drill the wells and conduct the operations which it currently has planned for the underlying properties.

MV Partners may transfer all or a portion of the underlying properties at any time, subject to specified limitations, and MV Partners may abandon individual wells or properties that it reasonably believes to be uneconomic. Under these circumstances, trust unitholders have no ability to prevent MV Partners from transferring the underlying properties to another operator, even if the trust unitholders do not believe that operator would operate the underlying properties in the same manner as MV Partners.

        MV Partners may at any time transfer all or part of the underlying properties. Trust unitholders are not entitled to vote on any transfer of the underlying properties, and the trust will not receive any proceeds from any such transfer, except in the limited circumstances when the net profits interest is released in connection with such transfer, in which case the trust will receive an amount equal to the fair market value of the net profits interest released. See "Business—Description of the Underlying Properties—Sale and Abandonment of Underlying Properties." Following any material sale or transfer of any of the underlying properties, such underlying properties will continue to be subject to the net profits interest of the trust, and the net proceeds attributable to the transferred property will be calculated as part of the computation of net proceeds described in this Form 10-K. MV Partners may delegate to the transferee responsibility for all of MV Partners' obligations relating to the net profits interest on the portion of the underlying properties transferred.

        MV Partners or any transferee of the underlying properties may abandon any well or property if it reasonably believes that the well or property can no longer produce oil or natural gas in commercially economic quantities. This could result in termination of the net profits interest relating to the abandoned well or property. In making such decisions, MV Partners and any such transferee will be required under the applicable conveyance to act as a reasonably prudent operator in the State of Kansas under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the net profits interest as a burden on such property.

The reserves attributable to the underlying properties are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production.

        The net proceeds payable to the trust from the net profits interest are derived from the sale of oil, natural gas and natural gas liquids produced from the underlying properties. The reserves attributable to the underlying properties are depleting assets, which means that the reserves attributable to the underlying properties will decline over time. As a result, the quantity of oil and natural gas produced from the underlying properties is expected to decline over time. Based on the estimated production volumes in the reserve report, the oil and natural gas production from proved reserves attributable to the underlying properties is projected to decline at an average annual rate of approximately 6.3% over the next 20 years assuming no additional developmental drilling or other capital expenditures are made after 2016 on the underlying properties. The anticipated rate of decline is an estimate and actual decline rates may vary from those estimated. The net profits interest will terminate on the later to occur of (1) June 30, 2026, or (2) the time when 14.4 MMBoe have been produced from the underlying properties and sold (which amount is the equivalent of 11.5 MMBoe in respect of the trust's right to receive 80% of the net proceeds from the underlying properties pursuant to the net profits interest).

        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

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market prices of oil, natural gas and natural gas liquids. In addition, because MV Partners has agreed to limit the amount of capital expenditures that may be taken into account in calculating net proceeds attributable to the net profits interest during a specified period preceding the termination of the net profits interest, MV Partners may choose to delay certain capital projects that may otherwise benefit the trust unitholders until the termination of the net profits interest. If operators of the wells to which the underlying properties relate 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 MV Partners or estimated in the reserve report.

        The trust agreement provides that the trust's business activities are limited to owning the net profits interest and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyance related to the net profits interest. As a result, the trust is not permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets and production attributable to the net profits interest.

        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 may be considered a return of capital as opposed to a return on investment. Eventually, the net profits interest may cease to produce in commercial quantities and the trust may, therefore, cease to receive any distributions of net proceeds therefrom.

The amount of cash available for distribution by the trust will be reduced by the amount of any production and development costs, taxes, capital expenditures and post-production costs.

        Production and development costs on the underlying properties are deducted in the calculation of the trust's share of net proceeds. In addition, production and property taxes, capital expenditures or post-production costs are deducted in the calculation of the trust's share of net proceeds. Accordingly, higher or lower production and development expenses, taxes, capital expenditures and post-production costs will directly decrease or increase the amount received by the trust in respect of its net profits interest. For a summary of these costs for the last three years, see "Item 1. Business—Description of the Underlying Properties—Producing Acreage and Well Counts." Historical costs may not be indicative of future costs.

        If development and production costs of the underlying properties exceed the proceeds of production from the underlying properties, the trust will not receive net proceeds from those properties until future proceeds from production exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs.

A purchaser's failure to pay MV Partners for purchased production could have a significant adverse impact on MV Partners, which in turn could result in MV Partners not having sufficient net proceeds attributable to the net profits interest for MV Partners to distribute cash to the trust.

        A purchaser's failure to pay for purchased production could have a significant adverse impact on MV Partners' business, which could in turn impact the trust. The recent tightening of credit in the financial markets may make it more difficult for purchasers to obtain financing and depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by such purchasers.

The trustee may, under certain circumstances, sell the net profits interest 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 net profits interest 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 net profits interest if the annual

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gross proceeds from the underlying properties attributable to the net profits interest are less than $1.0 million for each of any two consecutive years. The sale of the net profits interest will result in the dissolution of the trust. The net proceeds of any such sale will be distributed to the trust unitholders.

        The net profits interest will terminate on the later to occur of (1) June 30, 2026, or (2) the time when 14.4 MMBoe have been produced from the underlying properties and sold (which amount is the equivalent of 11.5 MMBoe in respect of the trust's right to receive 80% of the net proceeds from the underlying properties pursuant to the net profits interest). The trust unitholders are not entitled to receive any net proceeds from the sale of production from the underlying properties following the termination of the net profits interest. Therefore, the market price of the trust units will likely diminish toward the end of the term of the net profits interest because the cash distributions from the trust will cease at the termination of such net profits interest and the trust will have no right to any additional production from the underlying properties after the term of the net profits interest.

The disposal by the two members of MV Partners of their remaining trust units may reduce the market price of the trust units.

        As of the date this Form 10-K, the two members of MV Partners, MV Energy and VAP-I, owned 25% of the outstanding trust units. The two members of MV Partners may use some or all of the remaining trust units they own for a number of corporate purposes, including:

•

selling them for cash; and



•

exchanging them for interests in oil and natural gas properties or securities of oil and natural gas companies.

        If they sell additional trust units or exchange trust units in connection with acquisitions, then additional trust units will be available for sale in the market. The sale of additional trust units may reduce the market price of the trust units. MV Partners and the trust have entered into a registration rights agreement pursuant to which the trust has agreed to file a registration statement or a shelf registration statement to register the resale of the remaining trust units held by MV Partners and any transferee of the trust units upon request by such holders. See "Item 13. Certain Relationships and Related Transactions, and Director Independence—Registration Rights."

The market price for the trust units may not reflect the value of the net profits interest held by the trust.

        The trading price for publicly traded securities similar to the trust units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the trust will vary in response to numerous factors outside the control of the trust, including prevailing prices for sales of oil, natural gas and natural gas liquid production from the underlying properties. Consequently, the market price for the trust units may not necessarily be indicative of the value that the trust would realize if it sold the net profits interest to a third-party buyer. In addition, such market price may not necessarily reflect the fact that since the assets of the trust are depleting assets, a portion of each cash distribution paid on the trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. As a result, distributions made to a unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the unitholder.

Conflicts of interest could arise between MV Partners and the trust unitholders.

        The interests of MV Partners and the interests of the trust and the trust unitholders with respect to the underlying properties could at times differ. As a working interest owner in the underlying

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properties, MV Partners could have interests that conflict with the interests of the trust and the trust unitholders. For example:

•

MV Partners' interests may conflict with those of the trust and the trust unitholders in situations involving the development, maintenance, operation or abandonment of the underlying properties. MV Partners may make decisions with respect to development expenditures that adversely affect the underlying properties. These decisions include reducing development expenditures on these properties, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the trust in the future, or increasing development expenditures on the underlying properties during the final years of the term of the trust, which expenditures will benefit the unitholders only to the extent that they reduce the natural decline in oil and natural gas production during the term of the trust by an amount that more than offsets the cost of these development expenditures.



•

MV Partners may sell some or all of the underlying properties and such sale may not be in the best interests of the trust unitholders. In the event MV Partners sells all or any portion of the underlying properties, the purchaser of such underlying properties will acquire such underlying properties subject to the net profits interest relating thereto and, in connection therewith, such purchaser will be subject to the same standards of conduct with respect to development, operation and abandonment of such underlying properties as are imposed on MV Partners. MV Partners also has the right, subject to significant limitations as described herein, to cause the trust to release all or a portion of the net profits interest in connection with a sale of a portion of the underlying properties to which such net profits interest relates. In such an event, the trust is entitled to receive its proportionate share of the proceeds from the sale attributable to the net profits interest released. See "Business—Description of the Underlying Properties—Sale and Abandonment of Underlying Properties."

In addition, affiliates of MV Partners may engage in activities whereby such affiliates could have interests that conflict with the interests of MV Partners, which could, depending on the circumstances, negatively impact MV Partners' business.

        In making decisions with respect to the development, operation, abandonment or sale of the underlying properties, MV Partners and any successor operator will be required under the applicable conveyance to act as a reasonably prudent operator in the State of Kansas under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the net profits interest. Except for specified matters that require approval of the trust unitholders, the documents governing the trust do not provide a mechanism for resolving these conflicting interests.

The trust is managed by a trustee who cannot be replaced except at a special meeting of trust unitholders.

        The business and affairs of the trust are managed by the trustee. The voting rights of a trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for an annual or other periodic re-election of the trustee. The trust agreement provides that the trustee may only be removed and replaced by the holders of a majority of the outstanding trust units at a special meeting of trust unitholders called by either the trustee or the holders of not less than 10% of the outstanding trust units. MV Energy and VAP-I collectively own 25% of the outstanding trust units. As a result, it will be difficult to remove or replace the trustee, particularly without the approval of the members of MV Partners.

Trust unitholders have limited ability to enforce provisions of the net profits interest.

        The trust agreement permits the trustee to sue MV Partners or any other future owner of the underlying properties on behalf of the trust to enforce the terms of the conveyance creating the net

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profits interest. If the trustee does not take appropriate action to enforce provisions of the conveyance, recourse of the trust unitholders would be limited to bringing a lawsuit against the trustee to compel the trustee to take specified actions. The trust agreement expressly limits the trust unitholders' ability to directly sue MV Partners or any other third party other than the trustee. As a result, the unitholders will not be able to sue MV Partners or any future owner of the underlying properties to enforce these rights.

Courts outside of Delaware may not recognize the limited liability of the trust unitholders provided under Delaware law.

        Under the Delaware Statutory Trust Act, trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations under the General Corporation Law of the State of Delaware. Courts in jurisdictions outside of Delaware, however, may not give effect to such limitation.

The operations of the underlying properties may result in significant costs and liabilities with respect to environmental and operational safety matters, which could reduce the amount of cash available for distribution to trust unitholders.

        Significant costs and liabilities can be incurred as a result of environmental and safety requirements applicable to the oil and natural gas exploration, development and production activities of the underlying properties. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of the operations of the underlying properties.

        Strict, joint and several liability may be imposed under certain environmental laws, which could cause liability for the conduct of others or for the consequences of one's own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If it were not possible to recover the resulting costs through insurance or increased revenues, this could have a material adverse effect on the cash distributions to the trust unitholders. Please read "Item 1. Business—Description of the Underlying Properties—Regulation—Environmental Matters and Regulation" for more information.

Governmental authorities may enact climate change regulations that could increase MV Partners' costs to operate and, therefore, adversely affect distributions to the trust unitholders.

        Congress has considered recent proposed legislation directed at reducing greenhouse gas emissions and President Obama has indicated his support of legislation aimed at reducing greenhouse gases. The EPA has proposed rules to regulate greenhouse gases and regional initiatives have formed to control greenhouse gases. Additionally, the states in which MV Partners operates may implement air pollution control regulations that are more stringent than existing and proposed federal regulations, in particular the regulation of emissions of greenhouse gases. The adoption of laws and regulations to implement controls of greenhouse gases, including the imposition of fees or taxes, could adversely affect MV Partners' operations and, therefore, distributions to the trust unitholders.

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Regulation of greenhouse gases and climate change could adversely affect trust distributions.

        Some scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases, including carbon dioxide and methane, may be contributing to the warming of the Earth's atmosphere and other climatic changes. In response to such studies, the issue of climate change and the effect of greenhouse gas emissions, in particular emissions from fossil fuels, is attracting increasing attention worldwide. Legislative and regulatory measures to address concerns that emissions of greenhouse gases are contributing to climate change are in various phases of discussions or implementation at the international, national, regional and state levels.

        In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for greenhouse gases, became binding on the countries that ratified it. In the United States, federal legislation imposing restrictions on greenhouse gases is under consideration. Proposed legislation has been introduced that would establish an economy-wide cap on emissions of greenhouse gases and would require more sources of greenhouse gas emissions to obtain greenhouse gas emission "allowances" corresponding to their annual emissions. In addition, the EPA is taking steps that would result in the regulation of greenhouse gases as pollutants under the Clean Air Act. To date, the EPA has issued (i) a "Mandatory Reporting of Greenhouse Gases" final rule, effective December 29, 2009, which established a new comprehensive scheme requiring operators of stationary sources in the United States emitting more than established annual thresholds of carbon dioxide-equivalent greenhouse gases to inventory and report their greenhouse gas emissions annually and (ii) an "Endangerment Finding" final rule, effective January 14, 2010, which states the current and projected concentrations of six key greenhouse gases in the atmosphere, as well as emissions from new motor vehicles and new motor vehicle engines, threaten public health and welfare, allowing the EPA to finalize motor vehicle greenhouse gas standards (the effect of which could reduce demand for motor fuels refined from crude oil). Finally, according to the EPA, the final motor vehicle greenhouse gas standards will trigger construction and operating permit requirements for stationary sources. As a result, the EPA has proposed to tailor these programs such that only large stationary sources will be required to have air permits that authorize greenhouse gas emissions.

        Existing or future laws, regulations, treaties or international agreements related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on the operations of the underlying properties and the trust if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on the operations of the underlying properties and the trust. In addition to potential impacts on the operations of the underlying properties and the trust directly or indirectly resulting from climate-change legislation or regulations, the operations of the underlying properties and the trust also could be negatively affected by climate-change related physical changes or changes in weather patterns.

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 exploration, 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, MV Partners must obtain and maintain numerous permits, approvals and certificates from various federal, state, local and governmental authorities. MV Partners 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

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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. Please read "Item 1. Business—Description of the Underlying Properties—Regulation—Environmental Matters and Regulation."

The trust has not requested a ruling from the IRS regarding the tax treatment of ownership of the trust units or the tax treatment of the net profits interest. 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 net profits interest is not a debt instrument for federal income tax purposes, the trust unitholders may receive different and less advantageous tax treatment than that described in this Form 10-K.

        Tax counsel to MV Partners advised the trust at the time of formation that, for federal income tax purposes, in its opinion MV Partners will be treated as a grantor trust and not as an unincorporated business entity. Tax counsel to MV Partners also advised the trust at the time of formation that, for federal income tax purposes, based upon representations made by MV Partners regarding the expected economic life of the underlying properties and the expected duration of the net profits interest, in its opinion the net profits interest should be treated as a "production payment" under Section 636 of the Code or otherwise as a debt instrument.

        If the net profits interest were not treated as a debt instrument, or if the trust were not treated as a grantor trust, for federal income tax purposes, the tax treatment of tax items in respect of an investment in trust units may be affected. The effects of this different tax treatment may be less advantageous to trust unitholders.

        Neither MV Partners nor the trustee has requested a ruling from the IRS regarding these tax questions, and neither MV Partners nor the trust can assure the trust unitholders that such a ruling would be granted if requested or that the IRS will not challenge these positions on audit. See "Item 1. Business—Federal Income Tax Matters" for more information about the various matters described under this risk factor.

Certain U.S. federal income tax preferences currently available with respect to oil, natural gas liquids and natural gas production may be eliminated as a result of future legislation.

        Among the proposed changes contained in President Obama's Budget Proposal for Fiscal Year 2012 is the elimination of certain key U.S. federal income tax preferences relating to oil, natural gas and natural gas liquids exploration and production. The President's budget proposes to eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. Specifically, the budget proposes to repeal the deduction for percentage depletion with respect to wells.

The trust's net profits interest may be characterized as an executory contract in bankruptcy, which could be rejected in bankruptcy, thus relieving MV Partners from its obligations to make payments to the trust with respect to the net profits interest.

        MV Partners has recorded the conveyance of the net profits interest in Kansas in the real property records in each Kansas county where the properties are located. MV Partners has informed the trustee that MV Partners believes that the delivery and recording of the conveyance constitute fully conveyed and vested property interests in the trust under Kansas law. If in a bankruptcy proceeding in which

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MV Partners becomes involved as a debtor a determination were made that the conveyance constitutes an executory contract and the net profits interest is not a fully conveyed property interest under the laws of Kansas, and if such contract were not to be assumed in a bankruptcy proceeding involving MV Partners, the trust would be treated as an unsecured creditor of MV Partners with respect to such net profits interest in the pending bankruptcy proceeding.

        Oil and gas leases are real property interests under Colorado law. The net profits interest is a non-operating, non-possessory interest carved out of the oil and gas leasehold estate. MV Partners has informed the trustee that MV Partners believes that it is possible that the net profits interest for the underlying properties located in Colorado may not be treated as a real property interest under the laws of Colorado.. MV Partners has recorded the conveyance of the net profits interest in the real property records of Colorado in accordance with local recording acts. MV Partners has informed the trustee that MV Partners believes that, if, during the term of the trust, MV Partners becomes involved as a debtor in a bankruptcy proceeding, the net profits interest relating to the underlying properties located in Colorado should be treated as a fully conveyed personal property interest under the laws of Colorado. In such a proceeding, however, a determination could be made that the conveyance constitutes an executory contract and the net profits interest is not a fully conveyed personal property interest under the laws of Colorado, and if such contract were not to be assumed in a bankruptcy proceeding involving MV Partners, the trust would be treated as an unsecured creditor of MV Partners with respect to such net profits interest in the pending bankruptcy proceeding.

If the financial position of MV Partners degrades in the future, MV Partners may not be able to satisfy its obligations to the trust.

        MV Partners is a privately held limited liability company engaged in the exploration, development, production, gathering and aggregation and sale of oil and natural gas, primarily in the Mid-Continent region in the United States, and it is responsible for operating substantially all of the underlying properties. The operating agreement of MV Partners provides that Vess Oil and Murfin Drilling will operate the underlying properties on behalf of MV Partners for which MV Partners is designated as the operator. The conveyance provides that MV Partners is obligated to market, or cause to be marketed, the production related to the underlying properties.

        The ability of MV Partners to perform its obligations related to the operation of the underlying properties will depend on MV Partners' future financial condition and economic performance, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions, collections of payments due from third parties, and upon financial, business and other factors, many of which are beyond the control of MV Partners.

Item 1B.    Unresolved Staff Comments.

        None.

Item 2.    Properties.

        Reference is made to "Item 1—Business" and "Item 7—Trustee's Discussion and Analysis of Financial Condition and Results of Operations—Planned Development and Workover Program," which are incorporated herein by reference.

Item 3.    Legal Proceedings.

        Currently, there are no legal proceedings pending to which the trust is a party or of which any of its property is the subject.

Item 4.    Mine Safety Disclosures.

        None.

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PART II

Item 5.    Market for the Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

        The trust units commenced trading on the New York Stock Exchange on January 19, 2007 under the symbol "MVO." Prior to January 19, 2007, there was no established public trading market for the trust units. The following table sets forth, for the periods indicated, the high and low sales prices per unit, as reported on the New York Stock Exchange, and the amount of cash distributions declared per unit.

        As of March 12, 2012, the 11,500,000 units outstanding were held by 9 unitholders of record.

        Each quarter, the trustee determines the amount of funds available for distribution to the trust unitholders. Available funds are the excess cash, if any, received by the trust from the net profits interest, payments from hedge contracts that were in effect through 2010 and other sources (such as interest earned on any amounts reserved by the trustee) that quarter, over the trust's expenses for that quarter. Available funds will be reduced by any cash that the trustee decides to hold as a reserve against future expenses. It is expected that quarterly cash distributions during the term of the trust will be made by the trustee on or before the 25th day of the month following the end of each quarter to the trust unitholders of record on the 15th day of the month following the end of each quarter (or the next succeeding business day).

Equity Compensation Plans

        The trust does not have any employees and, therefore, does not maintain any equity compensation plans.

Recent Sales of Unregistered Securities

        There were no equity securities sold by the trust during the year ended December 31, 2011 that were not registered under the Securities Act of 1933, as amended, which we refer to as the "Securities Act."

Purchases of Equity Securities

        There were no purchases of trust units by the trust or any affiliated purchaser during the fourth quarter of the year ended December 31, 2011.

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Item 6.    Selected Financial Data.

        The following table sets forth selected data for the trust as of December 31, 2007, 2008, 2009, 2010 and 2011, and for the years ended December 31, 2007, 2008, 2009, 2010 and 2011 based on the audited statements of assets and trust corpus as of December 31, 2007, 2008, 2009, 2010 and 2011 and the audited statements of distributable income for the years ended December 31, 2007, 2008, 2009, 2010 and 2011.

Item 7.    Trustee's Discussion and Analysis of Financial Condition and Results of Operations.

        The following review of the trust's financial condition and results of operations should be read in conjunction with the financial statements and notes thereto. The trust's purpose is, in general, to hold the net profits interest and assigned interest in hedge contracts, to distribute to the trust unitholders cash that the trust receives in respect of the net profits interest and assigned interest in the hedge contracts (through 2010 when they expired) and to perform certain administrative functions in respect of the net profits interest and the trust units. The trust derives substantially all of its income and cash flows from the net profits interest.

Critical Accounting Policies

        The trust's financial statements are prepared on the following basis:

(a)

Net profits are recorded when received, including the effect of negative or positive adjustments, by the trustee on the last business day of each calendar quarter; and



(b)

Trust general and administrative expenses are recorded when paid.



(c)

The investment in net profits interest is amortized over the life of the trust based on units of production using the total estimated proved reserves.



(d)

The trustee reviews the carrying value of the net profits interest annually for impairment based on the projected income as estimated within the current reserve report.

        This manner of reporting income and expenses is considered to be the most meaningful because the quarterly distributions to trust unitholders are based on net cash receipts received from MV Partners. The financial statements of the trust differ from financial statements prepared in accordance with generally accepted accounting principles, because, under such principles, net profits and general and administrative expenses of the trust for a quarter would be recognized on an accrual basis.

Comparison of results of the trust for the years ended December 31, 2011 and 2010

        Income for the trust from the net profits interest and hedge activities was $40.6 million for the year ended December 31, 2011 compared to $32.5 million for the year ended December 31, 2010. General and administrative expense for the trust was $0.7 million for 2011 and $0.8 million for 2010. The trust paid administration fees of $0.1 million to MV Partners for each of 2011 and 2010. As of December 31, 2011 and 2010, the trust had $275,000 and $92,000, respectively, as a reserve for future expenses. Distributable income was $39.7 million or $3.4500 per unit in 2011 compared to $31.7 million or $2.7550 per unit in 2010.

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        The revenues from oil production are typically received by MV Partners one month after production; thus, the cash received by the trust during the year ended December 31, 2011 substantially represented the production by MV Partners from September 2010 through August 2011, and the cash received by the trust during the year ended December 31, 2010 substantially represented the production by MV Partners from September 2009 through August 2010. MV Partners computes net proceeds quarterly on a calendar basis and distributes to the trust 80% of the aggregate of such net proceeds attributable to a computation period on or before the 25th day of the month following the computation period. As a result, for the year ended December 31, 2011, the trust's net profits interest represented the cash proceeds received by the trust, which was based upon the cash receipts for the oil and gas production collected by MV Partners from October 1, 2010 through September 30, 2011. For the year ended December 31, 2010, the trust's net profits interest represented the cash proceeds received by the trust, which was based upon the cash receipts for the oil and gas production collected by MV Partners from October 1, 2009 through September 30, 2010.

        Excess of revenues over direct operating expenses and lease equipment and development costs from the underlying properties was $50.4 million for the period from October 1, 2010 through September 30, 2011. Included in this amount are payments to settle hedges totaling $3.8 million. In addition, amounts received to settle hedges was $0 for the period from October 1, 2010 through September 30, 2011, which resulted in total cash receipts over cash disbursements of $50.4 million. The trust's net profits interest (80%) of this total was $40.3 million for the year ended December 31, 2011. In addition, during 2011, MV Partners released and paid to the trust a net of $250,000 of the reserve for future capital expenditures, which resulted in total cash proceeds received by the trust of $40.6 million for the year ended December 31, 2011.

        Excess of revenues over direct operating expenses and lease equipment and development costs from the underlying properties was $40.6 million for the period from October 1, 2009 through September 30, 2010. Included in this amount are payments to settle hedges totaling $7.4 million. In addition, amounts received to settle hedges was $18,000 for the period from October 1, 2009 through September 30, 2010, which resulted in total cash receipts over cash disbursements of $40.7 million. The trust's net profits interest (80%) of this total was $32.5 million for the year ended December 31, 2010. In April 2010, MV Partners received payment of $5.6 million in connection with the SemGroup bankruptcy discussed in Note I of the Notes to Financial Statements, representing 100% of its claims for oil and gas sold to Eaglwing on and between July 2, 2008 and July 22, 2008. Such amount was included in the calculation of net proceeds attributable to the net profits interest of the trust for the year ended December 31, 2010.

        The trustee reserved $184,000 and $25,000 for future trust expenses for the years ended December 31, 2011 and 2010, respectively, and paid general and administrative expenses of $0.7 million and $0.8 million for the years ended December 31, 2011 and 2010, respectively, which resulted in distributable income of $39.7 million, or $3.450 per unit, for the year ended December 31, 2011 and $31.7 million, or $2.755 per unit, for the year ended December 31, 2010.

        The average price received for crude oil sold during 2011 was $86.46 per Bbl, while the average price received for crude oil sold during 2010 was $75.61 per Bbl. The average price received for natural gas sold during 2011 was $3.33 per Mcf, while the average price received for natural gas sold during 2010 was $3.46 per Mcf. The average prices for 2011 related to production by MV Partners from September 2010 through August 2011, and the average prices for 2010 related to production by MV Partners from September 2009 through August 2010.

        The overall production volumes sold and delivered to purchasers attributable to the 80% net profits interest that was for the oil and gas production sold and delivered during the period from October 1, 2010 to September 30, 2011 were 736,473 Bbls of oil, 62,610 Mcf of natural gas and 3,442 Bbls of natural gas liquids for a total equivalent barrels of oil of 749,145. The overall production

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volumes sold and delivered to purchasers attributable to the 80% net profits interest that was for the oil and gas production sold and delivered during the period from October 1, 2009 to September 30, 2010 were 757,887 Bbls of oil, 64,115 Mcf of natural gas and 3,464 Bbls of natural gas liquids for a total equivalent barrels of oil of 770,825.

        As noted above, the amounts reflected in the accompanying financial statements for the trust's year ended December 31, 2011 reflect cash received by the trust during the year. Such cash is primarily derived from production by MV Partners from September 2010 through August 2011. The amounts reflected in the accompanying financial statements for the trust's year ended December 31, 2010 reflect cash received by the trust during the year. Such cash is primarily derived from production by MV Partners from September 2009 through August 2010.

Comparison of results of the trust for the years ended December 31, 2010 and 2009

        Income for the trust from the net profits interest and hedge activities was $32.5 million for the year ended December 31, 2010 compared to $19.0 million for the year ended December 31, 2009. General and administrative expense for the trust was $0.8 million for each of 2010 and 2009. The trust paid administration fees of $0.1 million to MV Partners for each of 2010 and 2009. As of December 31, 2010 and 2009, the trust had $92,000 and $67,000, respectively, as a reserve for future expenses. Distributable income was $31.7 million or $2.7550 per unit in 2010 compared to $17.9 million or $1.5604 per unit in 2009.

        The revenues from oil production are typically received by MV Partners one month after production; thus, the cash received by the trust during the year ended December 31, 2010 substantially represented the production by MV Partners from September 2009 through August 2010, and the cash received by the trust during the year ended December 31, 2009 substantially represented the production by MV Partners from September 2008 through August 2009. MV Partners computes net proceeds quarterly on a calendar basis and distributes to the trust 80% of the aggregate of such net proceeds attributable to a computation period on or before the 25th day of the month following the computation period. As a result, for the year ended December 31, 2010, the trust's net profits interest represented the cash proceeds received by the trust, which was based upon the cash receipts for the oil and gas production collected by MV Partners from October 1, 2009 through September 30, 2010. For the year ended December 31, 2009, the trust's net profits interest represented the cash proceeds received by the trust, which was based upon the cash receipts for the oil and gas production collected by MV Partners from October 1, 2008 through September 30, 2009.

        Excess of revenues over direct operating expenses and lease equipment and development costs from the underlying properties was $40.7 million for the period from October 1, 2009 through September 30, 2010. Included in this amount are payments to settle hedges totaling $7.4 million. In addition, amounts received to settle hedges was $18,000 for the period from October 1, 2009 through September 30, 2010, which resulted in total cash receipts over cash disbursements of $40.7 million. The trust's net profits interest (80%) of this total was $32.5 million for the year ended December 31, 2010. In April 2010, MV Partners received payment of $5.6 million in connection with the SemGroup bankruptcy, representing 100% of its claims for oil and gas sold to Eaglwing on and between July 2, 2008 and July 22, 2008. Such amount was included in the calculation of net proceeds attributable to the net profits interest of the trust for the year ended December 31, 2010.

        Excess of revenues over direct operating expenses and lease equipment and development costs from the underlying properties was $24.1 million for the period from October 1, 2008 through September 30, 2009. Included in this amount are payments to settle hedges totaling $3.9 million. In addition, amounts received to settle hedges was $5.8 million for the period from October 1, 2008 through September 30, 2009, which resulted in total cash receipts over cash disbursements of $29.9 million. The trust's net profits interest (80%) of this total was $23.9 million. This amount was

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reduced by a recovery of the deficiency from the fourth quarter of 2008 in the amount of $4.9 million, which included applicable interest of $50,000, resulting in the income from net profits interest and hedge activities of $19.0 million for the year ended December 31, 2009.

        The trustee reserved $25,000 and $49,000 for future trust expenses for the years ended December 31, 2010 and 2009, respectively, and paid general and administrative expenses of approximately $0.8 million for each of the years ended December 31, 2010 and 2009, respectively, which resulted in distributable income of $31.7 million, or $2.755 per unit, for the year ended December 31, 2010 and $17.9 million, or $1.5604 per unit, for the year ended December 31, 2009.

        The average price received for crude oil sold during 2010 was $75.61 per Bbl, while the average price received for crude oil sold during 2009 was $54.03 per Bbl. The average price received for natural gas sold during 2010 was $3.46 per Mcf, while the average price received for natural gas sold during 2009 was $3.38 per Mcf. The average prices for 2010 related to production by MV Partners from September 2009 through August 2010, and the average prices for 2009 related to production by MV Partners from September 2008 through August 2009.

        The overall production volumes sold and delivered to purchasers attributable to the 80% net profits interest that is for the oil and gas production sold and delivered during the period from October 1, 2009 to September 30, 2010 were 757,887 Bbls of oil, 64,115 Mcf of natural gas and 3,464 Bbls of natural gas liquids for a total equivalent barrels of oil of 770,825. The overall production volumes sold and delivered to purchasers attributable to the 80% net profits interest that is for the oil and gas production sold and delivered during the period from October 1, 2008 to September 30, 2009 were 765,518 Bbls of oil, 70,297 Mcf of natural gas and 4,338 Bbls of natural gas liquids for a total equivalent barrels of oil of 780,054.

        As noted above, the amounts reflected in the accompanying financial statements for the trust's year ended December 31, 2010 reflect cash received by the trust during the year. Such cash is primarily derived from production by MV Partners from September 2009 through August 2010. The amounts reflected in the accompanying financial statements for the trust's year ended December 31, 2009 reflect cash received by the trust during the year. Such cash is primarily derived from production by MV Partners from September 2008 through August 2009.

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Historical Results of the Underlying Properties

        The following table sets forth revenues, direct operating expenses and the excess of revenues over direct operating expenses relating to the underlying properties for the three years in the period ended December 31, 2011. The historical results of the underlying properties are not indicative of the future distributions of the trust.

The above table sets forth information as it relates to the underlying properties on the accrual basis, which is the way the books and records are kept. These numbers do not relate to the trust as the trust reports on a cash basis. For the year ended December 31, 2009, the trust's net profits interest represents the cash proceeds received by the trust, which is based upon the cash receipts for the oil and gas production collected by MV Partners from October 1, 2008 through September 30, 2009. For the year ended December 31, 2010, the trust's net profits interest represents the cash proceeds received by the trust, which is based upon the cash receipts for the oil and gas production collected by MV Partners from October 1, 2009 through September 30, 2010. For the year ended December 31, 2011, the trust's net profits interest represents the cash proceeds received by the trust, which is based upon the cash receipts for the oil and gas production collected by MV Partners from October 1, 2010 through September 30, 2011.

        MV Partners has historically entered into certain hedging arrangements and other derivatives to reduce the exposure of the revenues from oil production for the underlying properties to fluctuations in crude oil prices. In addition, MV Partners was required under the terms of its original agreement of limited partnership to hedge approximately 80% of its expected annual proved producing reserves. This requirement is no longer in effect. From January 1, 2008 to December 31, 2010, approximately 74% of the actual oil production volumes were subject to these hedging arrangements, with settlement prices ranging from $56.39 to $70.57 per barrel. During that same period, the NYMEX price per barrel of crude oil was between $33.87 and $145.29. MV Partners has not entered into any hedge contracts relating to oil volumes expected to be produced after 2010, and the terms of the conveyance of the net profits interest prohibit MV Partners from entering into new hedging arrangements for the benefit of the trust.

        The following table provides oil and natural gas sales volumes, average sales prices and capital expenditures relating to the underlying properties for the three years in the period ended December 31,

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2011. Sales volumes for natural gas liquids during the periods presented were not significant. Average prices do not include the effect of hedge and other derivative activity.

Discussion and Analysis of Historical Results of the Underlying Properties

Comparison of Results of the Underlying Properties for the Years Ended December 31, 2011 and 2010

        Excess of revenues over direct operating expenses for the underlying properties was $57.3 million for the year ended December 31, 2011, compared to $38.0 million for the year ended December 31, 2010. The increase was primarily a result of an increase in total revenue as a result of an increase in the average price received for the oil sold in 2011 and a decrease in hedge expense. A small increase in direct operating expenses partially offset the increase in excess of revenues over direct operating expenses.

        Revenues.    Revenues from oil, natural gas and natural gas liquid sales increased $11.9 million to $80.9 million for the year ended December 31, 2011 compared to $69.0 million for the year ended December 31, 2010. This increase in revenues was primarily the result of an increase in the average price received for crude oil sold from $72.61 per Bbl for the year ended December 31, 2010 to $88.31 per Bbl for the year ended December 31, 2011. This increase in revenues reflects a decrease in the average price received for natural gas sold from $3.72 per Mcf for the year ended December 31, 2010 to $3.56 per Mcf for the year ended December 31, 2011. The revenues from oil, natural gas and natural gas liquids sales were also increased by a $9.2 million decrease in hedge activity expense. Total revenues increased $21.2 million from $59.7 million for the year ended December 31, 2010 to $80.9 million for the year ended December 31, 2011.

        Prices.    The average price received for crude oil sold increased from $72.61 per Bbl for the year ended December 31, 2010 to $88.31 per Bbl for the year ended December 31, 2011. The average price received for the crude oil sold increased primarily as a result of an increase in the oil price index on which the sales prices for a majority of the oil production were based. The average price received for natural gas sold decreased from $3.72 per Mcf for the year ended December 31, 2010 to $3.56 per Mcf for the year ended December 31, 2011. The average price received for natural gas sold decreased as a result of a decrease in the natural gas price index on which the sales prices for a majority of the natural gas production were based.

        Volumes.    Sales volumes for crude oil decreased from 944 MBbls for the year ended December 31, 2010 to 911 MBbls for the year ended December 31, 2011. Sales volumes for natural gas decreased from 76 MMcf for the year ended December 31, 2010 to 70 MMcf for the year ended December 31,

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2011. The small decrease in overall production sales volumes was less than the natural decline of the underlying properties.

        Hedge activity.    Hedge activity expense decreased from $9.2 million for the year ended December 31, 2010 to $0 for the year ended December 31, 2011. MV Partners entered into certain hedge contracts related to the oil production from the underlying properties for the year ended December 31, 2010. The weighted average settlement price of hedges for 2010 was $65.03 per Bbl. MV Partners has not entered into any hedge contracts relating to oil volumes to be produced after 2010, and the terms of the conveyance of the net profits interest prohibit MV Partners from entering into new hedging arrangements for the benefit of the trust.

        Bad debt expense.    During the year ended December 31, 2010, recovery was made from the Eaglwing bankruptcy for some of the 2008 sales previously written off as bad debts. MV Partners recognized bad debt recovery of $0.4 million for the year ended December 31, 2010. There were no bad debt expense or recoveries during the year ended December 31, 2011.

        Direct operating expenses.    Direct operating expenses increased from $22.1 million for the year ended December 31, 2010 to $23.7 million for the year ended December 31, 2011. This increase was primarily a result of an increase in lease operating expenses and property tax expense.

        Lease maintenance expense.    Lease maintenance expense increased from $1.7 million for the year ended December 31, 2010 to $1.9 million for the year ended December 31, 2011. This increase in lease maintenance expense was primarily the result of scheduled projects being completed.

        Production and property tax expense.    Production and property tax expense was $3.0 million for the year ended December 31, 2010 compared to $3.3 million for the year ended December 31, 2011. The increase was a result of higher property tax valuations and the increased revenue on which the production tax was calculated.

Comparison of Results of the Underlying Properties for the Years Ended December 31, 2010 and 2009

        Excess of revenues over direct operating expenses for the underlying properties was $38.0 million for the year ended December 31, 2010, compared to $33.7 million for the year ended December 31, 2009. The increase was primarily a result of an increase in total revenue as a result of an increase in the average price received for the oil sold in 2010, which was offset by an increase in hedge expense. A small increase in direct operating expenses partially offset the increase in excess of revenues over direct operating expenses.

        Revenues.    Revenues from oil, natural gas and natural gas liquid sales increased $16.6 million to $69.0 million for the year ended December 31, 2010 compared to $52.4 million for the year ended December 31, 2009. This increase in revenues was primarily the result of an increase in the average price received for crude oil sold from $54.82 per Bbl for the year ended December 31, 2009 to $72.61 per Bbl for the year ended December 31, 2010. This increase in revenues reflects an increase in the average price received for natural gas sold from $2.80 per Mcf for the year ended December 31, 2009 to $3.72 per Mcf for the year ended December 31, 2010. The increase in revenues from oil, natural gas and natural gas liquids sales was partially offset by the increase in hedge activity expense. Total revenues increased $4.3 million from $55.4 million for the year ended December 31, 2009 to $59.7 million for the year ended December 31, 2010.

        Prices.    The average price received for crude oil sold increased from $54.82 per Bbl for the year ended December 31, 2009 to $72.61 per Bbl for the year ended December 31, 2010. The average price received for the crude oil sold increased primarily as a result of an increase in the oil price index on which the sales prices for a majority of the oil production were based. The average price received for natural gas sold increased from $2.80 per Mcf for the year ended December 31, 2009 to $3.72 per Mcf

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for the year ended December 31, 2010. The average price received for natural gas sold increased as a result of an increase in the natural gas price index on which the sales prices for a majority of the natural gas production were based.

        Volumes.    Sales volumes for crude oil decreased from 949 MBbls for the year ended December 31, 2009 to 944 MBbls for the year ended December 31, 2010. Sales volumes for natural gas decreased from 86 MMcf for the year ended December 31, 2009 to 76 MMcf for the year ended December 31, 2010. The small decrease in overall production sales volumes was less than the natural decline of the underlying properties.

        Hedge activity.    Hedge activity expense increased from a $3.0 million gain for the year ended December 31, 2009 to a $9.2 million loss for the year ended December 31, 2010. This increase in hedge activity expense was due to the higher average NYMEX price per Bbl for 2010. The average NYMEX price per Bbl of crude oil for 2010 was $79.53 compared to $61.80 for 2009. The weighted average settlement price of hedges for 2010 was $65.03 compared to $66.24 for 2009.

        Bad debt expense.    For the year ended December 31, 2009, MV Partners wrote off 8% of the revenue from production sold to Eaglwing during June 2008 and the first 18 days of July 2008 as a result of the Eaglwing bankruptcy. MV Partners also wrote off $16,000 due from SemCrude for the settlement of certain hedge contracts. During the year ended December 31, 2010, recovery was made from the bankruptcy court for some of the 2008 sales. MV Partners recognized bad debt recovery of $0.4 million for the year ended December 31, 2010.

        Direct operating expenses.    Direct operating expenses increased from $20.4 million for the year ended December 31, 2009 to $22.1 million for the year ended December 31, 2010. This increase was primarily a result of an increase in lease operating expenses and property tax expense.

        Lease maintenance expense.    Lease maintenance expense increased from $1.4 million for the year ended December 31, 2009 to $1.7 million for the year ended December 31, 2010. This increase in lease maintenance expense was primarily the result of scheduled projects being completed.

        Production and property tax expense.    Production and property tax expense was $2.2 million for the year ended December 31, 2009 compared to $3.0 million for the year ended December 31, 2010. The increase was a result of higher property tax valuations and the increased revenue on which the production tax was calculated.

Liquidity and Capital Resources

        Other than trust administrative expenses, including any reserves established by the trustee for future liabilities, the trust's only use of cash is for distributions to trust unitholders. Administrative expenses include payments to the trustee as well as an annual administrative fee to MV Partners pursuant to the administrative services agreement. Each quarter, the trustee determines the amount of funds available for distribution. Available funds are the excess cash, if any, received by the trust from the net profits interest and payments from other sources (such as interest earned on any amounts reserved by the trustee) in that quarter, over the trust's expenses for that quarter. Available funds are reduced by any cash the trustee decides to hold as a reserve against future expenses. As of December 31, 2011, $275,000 was held by the trustee as such a reserve. The trustee may cause the trust to borrow funds required to pay expenses if the trustee determines that the cash on hand and the cash to be received are insufficient to cover the trust's liabilities. If the trust borrows funds, the trust unitholders will not receive distributions until the borrowed funds are repaid. During each of 2010 and 2011, MV Partners made no advances to the trust for trust expenses.

        Income to the trust from the net profits interest is based on the calculation and definitions of "gross proceeds" and "net proceeds" contained in the conveyance.

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        As further discussed below, MV Partners' development and workover program will require MV Partners to make future capital expenditures in connection with the development, exploration and production of oil and gas. Substantially all of the underlying properties are located in mature fields and MV Partners does not expect future costs for the underlying properties to change significantly as compared to recent historical costs other than increases due to increases in the general cost of oilfield services.

        The trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the trust's liquidity or the availability of capital resources.

Planned Development and Workover Program

        Since acquiring the underlying properties in 1998 and 1999, MV Partners has implemented a development program on the underlying properties to develop further proved undeveloped reserves and to help offset the natural decline in production. These activities included recompletion of certain existing wells into new producing horizons, workovers of existing wells, and the drilling of infill development wells.

        The development program that MV Partners currently intends to implement over the five years ending December 31, 2016 with respect to the underlying properties categorized as proved undeveloped reserves consists of drilling development wells, recompletion and workover projects, and polymer workovers. The development program that MV Partners currently intends to implement over the next five years with respect to the underlying properties categorized as proved developed non-producing reserves consists of well-reactivation projects, injection well-workover projects, recompletion projects, and well-workover projects.

        MV Partners has undertaken 3-D seismic surveys covering several leases constituting a part of the underlying properties. These leases have over 31 undrilled offset locations of varying quality based on offset production and subsurface mapping. The 3-D data was utilized to refine the subsurface mapping with respect to the size of mapped sink holes and to define smaller structural features along the edges of the main formation reservoir. Using this data, MV Partners has scheduled the drilling of 17 proved undeveloped locations over the five years ending December 31, 2016. MV Partners has expanded its 3-D seismic program into other fields constituting a part of the underlying properties.

        MV Partners expects total capital expenditures for the underlying properties during the five years ending December 31, 2016 will be approximately $13.0 million. Of this total, MV Partners contemplates spending approximately $9.0 million to drill development wells in seven project areas and approximately $4.0 million for recompletion and workovers of existing wells. MV Partners expects that these capital projects will add production that will partially offset the natural decline in production otherwise expected to occur with respect to the underlying properties. The trust is not directly obligated to pay any portion of any capital expenditures made with respect to the underlying properties; however, capital expenditures made by MV Partners with respect to the underlying properties will be deducted from the gross proceeds in calculating the net proceeds from which cash will be paid to the trust. As a result, the trust will indirectly bear an 80% (subject to certain limitations during the final three years of the trust, as described above under "Item 1. Business—Computation of Net Proceeds—Net Profits Interest") share of any capital expenditures made with respect to the underlying properties. Accordingly, higher or lower capital expenditures will, in general, directly decrease or increase, respectively, the cash received by the trust in respect of its net profits interest. As the cash received by the trust in respect of the net profits interest will be reduced by the trust's pro rata share of these capital expenditures, MV Partners expects that it will incur capital expenditures with respect to the underlying properties throughout the term of the trust on a basis that balances the impact of the capital expenditures on current cash distributions to the trust unitholders with the longer term benefits

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of increased oil and natural gas production expected to result from the capital expenditures. In addition, MV Partners may establish a capital reserve of up to $1.0 million in the aggregate at any given time to reduce the impact on distributions of uneven capital expenditure timing.

        MV Partners, as the operator of the underlying properties, is entitled to make all determinations related to capital expenditures with respect to the underlying properties, and there are no limitations on the amount of capital expenditures that MV Partners may incur with respect to the underlying properties, except as described above under "Item 1. Business—Computation of Net Proceeds—Net Profits Interest." As the trust unitholders would not be expected to fully realize the benefits of capital expenditures made with respect to the underlying properties toward the end of the term of the trust, during each twelve-month period beginning on the later to occur of (1) June 30, 2023, and (2) the time when 13.2 MMBoe have been produced from the underlying properties and sold (which is the equivalent of 10.6 MMBoe in respect of the net profits interest), capital expenditures that may be taken into account in calculating net proceeds attributable to the net profits interest will be limited to the average annual capital expenditures during the preceding three years, as adjusted for inflation. See "Item 1. Business—Computation of Net Proceeds—Net Profits Interest."

Off-Balance Sheet Arrangements

        The trust has no off-balance sheet arrangements. The trust has not guaranteed the debt of any other party, nor does the trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.

Contractual Obligations

        As of December 31, 2011, the trust had no obligations or commitments to make future contractual payments other than the administrative services fee and trustee fee payable to MV Partners and the trustee, respectively. See "Item 8. Financial Statements and Supplementary Data—Notes to Financial Statements—Note G—Related Party Transactions."

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk.

        Substantially all of the income to the trust is derived from the net profits interest, which generally entitles the trust to receive 80% of the net proceeds from oil and gas production from the underlying properties. Consequently, the trust is exposed to market risk from fluctuations in oil and gas prices. Although the trust may borrow money to pay expenses of the trust, the amount of any such borrowings is unlikely to be material to the trust. As a result, the trust is not subject to any material interest rate market risk.

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Item 8.    Financial Statements and Supplementary Data.

        Report of Independent Registered Public Accounting Firm

To the Trustee and Unitholders
MV Oil Trust

        We have audited the accompanying statements of assets and trust corpus of MV Oil Trust (the "Trust") as of December 31, 2010 and 2011 and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Trust's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        As described in Note B to the financial statements, these financial statements have been prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

        In our opinion, the financial statements referred to above present fairly, in all material respects, the assets and trust corpus of MV Oil Trust as of December 31, 2010 and 2011 and its distributable income and its changes in trust corpus for each of the three years in the period ended December 31, 2011, on the basis of accounting described in Note B.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), MV Oil Trust's internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 14, 2012 expressed an unqualified opinion thereon.

/s/ Grant Thornton LLP

Wichita, Kansas
March 14, 2012

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MV OIL TRUST

STATEMENTS OF ASSETS AND TRUST CORPUS

STATEMENTS OF DISTRIBUTABLE INCOME

STATEMENTS OF CHANGES IN TRUST CORPUS

The accompanying notes are an integral part of these statements.

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MV Oil Trust

NOTES TO FINANCIAL STATEMENTS

NOTE A—ORGANIZATION OF THE TRUST

        MV Oil Trust (the "Trust") is a statutory trust formed on August 3, 2006, under the Delaware Statutory Trust Act pursuant to a Trust Agreement (the "Trust Agreement") among MV Partners, LLC ("MV Partners") as trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the "Trustee"), and Wilmington Trust Company, as Delaware Trustee (the "Delaware Trustee").

        The Trust was created to acquire and hold a term net profits interest for the benefit of the Trust unitholders pursuant to a conveyance from MV Partners to the Trust. The term net profits interest is an interest in underlying properties consisting of MV Partner's net interests in all of its oil and natural gas properties located in the Mid-Continent region in the states of Kansas and Colorado (the "underlying properties"). These oil and gas properties include approximately 1,000 producing oil and gas wells.

        The net profits interest is passive in nature, and the Trustee has no management control over and no responsibility relating to the operation of the underlying properties. The net profits interest entitles the Trust to receive 80% of the net proceeds attributable to MV Partners' interest from the sale of production from the underlying properties. The net profits interest will terminate on the later to occur of (1) June 30, 2026 or (2) the time when 14.4 million barrels of oil equivalent (MMBoe) have been produced from the underlying properties and sold (which amount is the equivalent of 11.5 MMBoe with respect to the Trust's 80% net profits interest), and the Trust will soon thereafter wind up its affairs and terminate.

        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 or the Delaware Trustee as a lender provided the terms of the loan are similar to the terms it would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself and make other short term investments with the funds distributed to the Trust.

NOTE B—TRUST ACCOUNTING POLICIES

        A summary of the significant accounting policies of the Trust follows.

1.     Basis of accounting

        The Trust uses the modified cash basis of accounting to report Trust receipts of the term net profits interest, receipts under the hedge contracts previously entered into and payments of expenses incurred. The term net profits interest is revenues (oil, gas and natural gas liquid sales net of any payments made in connection with the settlement of the hedge and other derivative contracts) less direct operating expenses (lease operating expenses, lease maintenance, lease overhead, and production and property taxes) and an adjustment for lease equipment cost and lease development expenses (which are capitalized in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP)) of the underlying properties times 80% (term net profits interest percentage). In addition, the Trust was entitled to receive 80% of all payments received by MV Partners upon settlement of the hedge and other derivative contracts prior to their termination. Actual cash receipts may vary due to timing delays of actual cash receipts from the property operators or purchasers and due to wellhead and pipeline volume balancing agreements or practices. The actual cash distributions of the Trust will be made based on the terms of the conveyance creating the Trust's net profits interest.

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MV Oil Trust

NOTES TO FINANCIAL STATEMENTS (Continued)

NOTE B—TRUST ACCOUNTING POLICIES (Continued)

        The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust's assets, Trust corpus, and distributable income as follows:

        a)    Income from Net Profits Interest is recorded when distributions are received by the Trust;

        b)    Distributions to Trust unitholders are recorded when paid by the Trust;

        c)     Trust general and administrative expenses (which includes the Trustee's fees as well as accounting, engineering, legal and other professional fees) are recorded when paid;

        d)    Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under U.S. GAAP;

        e)    Amortization of the investment in Net Profits Interest is calculated using the units-of-production method based upon total estimated proved reserves, is charged directly to trust corpus and does not affect distributable income; and

        f)     The Trust evaluates its investment in the net profits interest periodically for impairment purposes. The Trust will provide a write-down to its investment in the net profits interest if and when that total capitalized costs, less accumulated amortization, exceed undiscounted future cash flows attributable to the Trust's interests in the proved oil and gas reserves of the underlying properties.

        While these statements differ from financial statements prepared in accordance with U.S. GAAP, the modified cash basis of reporting income and distributions is considered most meaningful because quarterly distributions to the Trust unitholders are based on net cash receipts.

        This comprehensive basis of accounting other than generally accepted accounting principles corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission (the "SEC") as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

2.     Cash equivalents

        For purposes of these statements, the Trust considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

3.     Use of estimates

        The preparation of financial statements requires estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

        Significant estimates affecting these financial statements include estimates of proved oil and gas reserves, which are used to compute the Trust's amortization of net profits interest.

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MV Oil Trust

NOTES TO FINANCIAL STATEMENTS (Continued)

NOTE C—NET PROFITS INTEREST

        The net profits interest was recorded at the historical cost of MV Partners on January 24, 2007, the date of conveyance, and is calculated as follows:

NOTE D—INCOME FROM NET PROFITS INTEREST AND HEDGE AND OTHER DERIVATIVE ACTIVITIES