Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

The co-registrants hereby amend this registration statement on such date or dates as may be necessary to delay its effective date until the co-registrants shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

This is an initial public offering of units of beneficial interest in the MV Oil Trust. MV Partners, LLC, which we refer to as "MV Partners" in this prospectus, has formed the trust and, immediately prior to the closing of this offering, MV Partners will contribute a term net profits interest in oil and natural gas properties to the trust in exchange for 11,500,000 trust units. MV Partners is offering all of the trust units to be sold in this offering and MV Partners will receive all proceeds from the offering. MV Partners is a privately-held limited liability company engaged in the exploration, development, production, gathering, aggregation and sale of oil and natural gas from properties located in Kansas and eastern Colorado.

There is currently no public market for the trust units. MV Partners expects that the public offering price will be between $19.00 and $21.00 per trust unit. The trust units have been approved for listing on the New York Stock Exchange under the symbol "MVO."

Trust units are units of beneficial interest in the trust and represent undivided interests in the trust. They do not represent any interest in MV Partners.

Investing in the trust units involves a high degree of risk. Before buying any trust units, you should read the discussion of material risks of investing in the trust units in "Risk Factors" beginning on page 20 of this prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The underwriters may also exercise their option to purchase from the members of MV Partners up to 1,125,000 additional trust units at the initial public offering price, less the underwriting discounts and commissions, within 30 days of the date of this prospectus.

The underwriters are offering the trust units as set forth under "Underwriting." Delivery of the trust units will be made on or about , 2007.

Geographic Location of the Major Producing Areas
of the Underlying Properties in the State of Kansas

You should rely only on the information contained in this prospectus. The trust has not, MV Partners has not and the underwriters have not, authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. The trust is not, MV Partners is not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only.

This summary highlights information contained elsewhere in this prospectus. To understand this offering fully, you should read the entire prospectus carefully, including the risk factors and the financial statements and notes to those statements. You will find definitions for terms relating to the oil and natural gas business in "Glossary of Certain Oil and Natural Gas Terms." Cawley, Gillespie & Associates, Inc., an independent engineering firm, provided the estimates of proved oil and natural gas reserves as of June 30, 2006, included in this prospectus. These estimates are contained in a summary prepared by Cawley, Gillespie & Associates, Inc. of its reserve report as of June 30, 2006, for the underlying properties described below. This summary is located at the back of this prospectus as Appendix A, and is referred to in this prospectus as the "reserve report." Unless otherwise indicated, all information in this prospectus assumes no exercise of the underwriters' option to purchase additional trust units.

MV Oil Trust was formed in August 2006, by MV Partners, LLC, which we refer to as "MV Partners." Immediately prior to the closing of this offering, MV Partners will convey 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 the date of the conveyance of the net profits interest to the trust, which we refer to as the "net profits interest." These properties are located in the Mid-Continent region in the States of Kansas and Colorado. We refer to MV Partners' net interests in such properties, after deduction of all royalties and other burdens on production thereon as of the date of the conveyance of the net profits interest to the trust, as the "underlying properties." As of June 30, 2006, the underlying properties produced predominantly oil from approximately 985 wells, and the projected reserve life of the underlying properties was in excess of 50 years. Based on the reserve report, the net profits interest would entitle the trust to receive net proceeds from the sale of production of 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 85% were classified as proved developed producing reserves as of June 30, 2006. Production from the underlying properties for the year ended December 31, 2005, 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. See "—Planned Development and Workover Program" for a summary of MV Partners' development plans.

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 gross proceeds used to calculate the net profits interest will be 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 will deduct 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 is a party at the time of the closing of this offering, which we refer to as the "hedge contracts." In addition, immediately prior to the closing of this offering, MV Partners will assign 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 will deduct 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. For a more complete description of the calculation of net proceeds, see "Computation of Net Proceeds."

Net proceeds payable to the trust will 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 of those excess costs, plus interest at the prime rate. For the nine months ended September 30, 2006, lease operating expenses were $11.06 per Boe, and lease maintenance expenses, lease overhead and production and property taxes were $7.68 per Boe, for an aggregate lifting cost of $18.74 per Boe. As substantially all of the underlying properties are located in mature fields, 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 cost of oilfield services generally.

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 first quarterly distribution is expected to be made on or about February 23, 2007 to trust unitholders owning trust units on February 15, 2007. The trust's first quarterly distribution will consist 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, this cash payment will include 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. As a result of the long period of time that will be included in the first quarterly distribution, subsequent quarterly distributions are likely to be less than the initial distribution. The second quarterly distribution is expected to be made on or about April 25, 2007 to trust unitholders owning trust units on April 16, 2007. The second quarterly distribution will consist of the net proceeds of production collected from the closing of this offering until March 31, 2007, together with 80% of all amounts payable to MV Partners from hedge contract counterparties during such period resulting from the monthly settlements of the hedge contracts. In addition, in connection with the trust's second quarterly distribution, MV Partners will pay the trust an amount equal to the amount that would have been payable to the trust as of the closing of this offering had the net profits interest been in effect since January 1, 2007. Furthermore, this cash payment by MV Partners will include 80% of all amounts paid to MV Partners from hedge contract counterparties for settlements related to the period from January 1, 2007 to the closing of this offering. 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 your original investment.

For the years 2006, 2007 and 2008, MV Partners has entered into swap contracts and costless collars at prices ranging from $56 to $68 per barrel of oil that hedge approximately 82% to 86% of expected production from the proved developed producing reserves attributable to the underlying properties in the reserve report. For the years 2009 and 2010, MV Partners has entered into swap contracts at prices ranging from $63 to $71 per barrel of oil that hedge approximately 80% of expected production from the proved developed producing reserves attributable to underlying properties in the reserve report. These hedge contracts should reduce the commodity price-related risks inherent in holding interests in oil, a commodity that has historically been characterized by significant price volatility, during the term of the hedge contracts.

The business and affairs of the trust will be managed by the trustee, and MV Partners and its affiliates have no ability to manage or influence the operations of the trust. The properties comprising 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, the sole manager of MV Partners.

An investment in the trust units involves risks associated with fluctuations in energy commodity prices, the operation of the underlying properties, certain regulatory and legal matters, the structure of the trust and the tax characteristics of the trust units. The following list of factors is not exhaustive. Please read carefully these risks and other risks described under "Risk Factors."

The trust will issue 11,500,000 units to MV Partners prior to the completion of this offering, and MV Partners will sell approximately 65% of these units in this offering, or MV Partners and its two members will sell a combined 75% if the underwriters' option to purchase additional trust units from the members is exercised in full.

The following chart shows the relationship of MV Partners, the trust and the public trust unitholders, assuming no exercise of the underwriters' option to purchase additional trust units.

The underlying properties consist of MV Partners' net interests in all of its oil and natural gas properties after deduction of all royalties and other burdens on production thereon as of the date of conveyance of the net profits interest to the trust. These oil and natural gas properties consist of approximately 985 producing oil and natural gas wells on approximately 202 leases. 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 natural gas company. As of June 30, 2006, proved reserves attributable to the underlying properties, as estimated in the reserve report, were approximately 18.7 MMBoe with a PV-10 of $358.7 million. During the nine months ended September 30, 2006, average net daily production from the underlying properties was 2,883 Boe per day. MV Partners' interests in the

properties comprising 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. Affiliates of MV Partners are currently the operators or contract operators of substantially all of the underlying properties. Based on the reserve report, the net profits interest would entitle the trust to receive net proceeds from the sale of production of approximately 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 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.

MV Partners' interest in the underlying properties after deducting the net profits interest entitles it to 20% 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 and all of the net proceeds thereafter. The trust units retained by the two members of MV Partners, which represent approximately 35% of the trust units following the closing of this offering, assuming no exercise of the underwriters' option to purchase additional trust units, are subject to lock-up arrangements. See "Trust Units Eligible for Future Sale—Lock-up Agreements." MV Partners believes that its retained ownership interests in the underlying properties and its members' ownership of trust units, which collectively entitle MV Partners and its members to receive 48% of the net proceeds from the underlying properties, will provide sufficient incentive to operate (or cause to be operated) and develop the oil and natural gas properties comprising the underlying properties in an efficient and cost-effective manner. In addition, MV Partners has agreed to use commercially reasonable efforts to cause the operators of the underlying properties to operate these properties in the same manner it would if these properties were not burdened by the net profits interest.

As of June 30, 2006, approximately 76% of the proved reserves attributable to the underlying properties and 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 histories and numerous additional development opportunities to help reduce the natural decline in production from the underlying properties. See "—Planned Development and Workover Program" for a summary of MV Partners' development plans. Approximately 98% of the future production from the underlying properties is expected to be oil and the remaining production is expected to be natural gas and natural gas liquids.

Since acquiring the underlying properties in 1998 and 1999, MV Partners has implemented a development program on the properties comprising the underlying properties to further develop proved undeveloped reserves and help reduce the natural decline in production. These activities included recompletion of certain existing wells into new producing horizons, the drilling of infill development wells, 3-D seismic surveys, workover programs and implementing new technologies in various projects.

MV Partners expects total capital expenditures for the underlying properties during the next five years will be approximately $17 million. Of this total, MV Partners contemplates spending approximately $12.8 million to drill approximately 65 development wells in ten project areas and approximately $4.1 million for recompletions and workovers of existing wells. MV Partners expects that these capital projects will add production that will partially reduce the natural decline in production otherwise expected to occur with respect to the underlying properties, as described in more detail below. 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 below) 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 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 below. As the trust unitholders would not be expected to fully realize the benefits of capital expenditures made with respect to the underlying properties towards 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 "Computation of Net Proceeds—Net Profits Interest."

MV Partners is a privately-held limited liability company engaged in the exploration, development, production, gathering, aggregation and sale of oil and natural gas from properties located in Kansas and eastern Colorado. MV Partners was formed in August 2006 as a result of the conversion of MV Partners, LP to a limited liability company. MV Partners, LP was formed in 1998 to acquire oil and natural gas properties and related assets located in Kansas and eastern Colorado from a major oil and gas company. MV Energy, LLC, which was also formed in 1998, serves as the sole manager of MV Partners and was previously the general partner of MV Partners, LP until its conversion into a limited liability company in August 2006. MV Energy is owned equally by Vess Acquisition Group, L.L.C. and Murfin, Inc. Vess Oil and Murfin Drilling operate the properties held by MV Partners for which MV

Partners is designated as the operator. Vess Oil and Murfin Drilling have collectively operated oil and natural gas properties in Kansas for more than 70 years and, according to the 2005 Kansas Geological Survey, were the largest and the third largest operators of oil properties in Kansas, respectively, measured by production. As of June 30, 2006, MV Partners held interests in approximately 985 gross (902 net) producing wells, and proved reserves of the underlying properties were approximately 18.7 MMBoe.

For the year ended December 31, 2005, MV Partners had revenues and net income of $36.2 million and $13.1 million, respectively. For the nine months ended September 30, 2006, MV Partners had revenues and net income of $35.5 million and $13.6 million, respectively, compared to revenues and net income for the nine months ended September 30, 2005 of $25.8 million and $8.8 million, respectively. As of September 30, 2006, MV Partners had total assets of $72.9 million and total liabilities of $106.4 million, including bank debt outstanding of $83.0 million. As of June 30, 2006, the underlying properties owned by MV Partners had a PV-10 of $358.7 million. Giving pro forma effect to the offering of the trust units contemplated by this prospectus and the application of the net proceeds as described in "Use of Proceeds," as of September 30, 2006, MV Partners would have had total assets of $51.0 million and total liabilities of $164.5 million, including bank debt outstanding of $25.0 million.

The address of MV Partners is 250 N. Water, Suite 300, Wichita, Kansas 67202 and its telephone number is (316) 267-3241.

The following are some key investment considerations related to the underlying properties, the net profits interest and the trust units:

Summary Proved Reserves of Underlying Properties and Net Profits Interest. As of June 30, 2006, estimated proved reserves attributable to the underlying properties were approximately 98% oil and 2% natural gas and natural gas liquids, based on the reserve report. The following table sets forth, as of June 30, 2006, certain estimated proved oil, natural gas and natural gas liquid reserves, estimated future net revenues and the discounted present value thereof attributable to the underlying properties and the net profits interest, in each case derived from the reserve report. The reserve report was prepared by Cawley, Gillespie & Associates, Inc. in accordance with criteria established by the Securities and Exchange Commission, or SEC. Proved reserves reflected in the table below for the underlying properties and the net profits interest are based on oil, natural gas and natural gas liquid prices realized by MV Partners as of June 30, 2006, which were $70.68 per Bbl of oil, $5.07 per Mcf of natural gas and $56.37 per Bbl of natural gas liquids. Oil equivalents in the table are the sum of the Bbls of oil, the Boe of the stated Mcfs of natural gas, calculated on the basis that six Mcfs of natural gas is the energy equivalent of one Bbl of oil, and the Boe of the stated Bbls of natural gas liquids, calculated on the basis that 1.54 Bbls of natural gas liquids is the energy equivalent of one Bbl of oil. The estimated future net revenues attributable to the net profits interest as of June 30, 2006, are net of the trust's proportionate share of all estimated costs deducted from revenue pursuant to the terms of the conveyance creating the net profits interest and include only the reserves attributable to the underlying properties that are expected to be produced within the term of the net profits interest. The estimated future net revenues from proved reserves also gives effect to the impact of the hedge contracts on the price received in connection with the sale of oil production from the underlying properties. The reserve report is included as Appendix A to this prospectus.

	Proved Reserves	Estimated Future Net Revenues from Proved Reserves
	Oil (MBbl)	Natural Gas (MMcf)	Natural Gas Liquids (MBbl)	Oil Equivalent (MBoe)	Undiscounted		Discounted(1)
					(in thousands, except per unit data)
Underlying properties (100%)(2)	18,424	1,422	106	18,730	$	784,132		$	358,737
Underlying properties (80%)(3)	11,302	1,006	71	11,516	$	523,423		$	278,629
Net profits interest(4)	7,318	683	48	7,463	$	523,423		$	278,629
Amount per trust unit(5)	—	—	—	—	$	45.52		$	24.23

Annual Production Attributable to Net Profits Interest. The following graph shows estimated monthly production of total proved reserves attributable to the net profits interest during the term of the net profits interest based upon the pricing and other assumptions set forth in the reserve report. This graph presents the total proved reserves broken down by three reserve categories: proved developed producing, proved developed non-producing and proved undeveloped reserves, which demonstrates the impact of developmental drilling and well re-completion and workover activities that MV Partners expects to undertake with respect to the underlying properties within the next five years. For a description of MV Partners' planned development, workover and recompletion programs over the next five years, see "The Underlying Properties—Planned Development and Workover Program."

Estimated Annual Production of Proved Reserves
Attributable to the Net Profits Interest

The selected financial data presented below should be read in conjunction with the audited statements of historical revenues and direct operating expenses and the unaudited statements of historical revenues and direct operating expenses of the underlying properties, the related notes and "Discussion and Analysis of Historical Results of the Underlying Properties" included elsewhere in this prospectus. 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, 2005, and for the nine-month periods ended September 30, 2005 and 2006, derived from the underlying properties' audited and unaudited statements of historical revenues and direct operating expenses included elsewhere in this prospectus. The unaudited statements were prepared on a basis consistent with the audited statements and, in the opinion of MV Partners, include all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the revenues, direct operating expenses and the excess of revenues over direct operating expenses relating to the underlying properties for the periods presented.

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. As a result of the repurchase of the limited partner interest in MV Partners in 2005 as described in "MV Partners," this requirement is no longer in effect. From 2003 to 2005, approximately 70% to 74% of the actual oil production volumes were subject to these hedging arrangements with settlement prices ranging from $20.10 to $33.60 per barrel. During that same period, the average NYMEX price per barrel of crude oil was between $31.07 and $56.67. These hedging arrangements have now expired and will not impact the amount of cash available for distribution to the trust. The settlement prices of the existing hedge contracts range from $56 to $71 and are more consistent with current crude oil prices. The following table sets forth the excess of revenues over direct operating expenses for the underlying properties, excluding the effects of hedges and other derivative activity, for the years ended December 31, 2003, 2004 and 2005 and for the nine months ended September 30, 2005 and 2006. Although not prescribed by generally accepted accounting principles, MV Partners believes the presentation of this information is relevant and useful because it helps investors in the trust units

understand the operating performance of the underlying properties unaffected by these hedging arrangements and other derivatives, which have now expired. The management of MV Partners uses this information for similar purposes. These amounts should not be considered in isolation from or as a substitute for any other financial measure.

Under the terms of the conveyance of the net profits interest, 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, production and property taxes paid by MV Partners will be deducted from the gross proceeds derived from the sale of production from the underlying properties and any payments made by MV Partners under the hedge contracts will be included for purposes of determining the amount of the quarterly net profits interest payment to be made to the trust. In addition, the trust will be entitled to receive 80% of all amounts payable to MV Partners from hedge contract counterparties upon monthly settlements of the hedge contracts. Trust unitholders are not obligated to bear any administrative expenses of MV Partners, except that the trust has entered into an administrative services agreement with MV Partners pursuant to which MV Partners has agreed to perform specified administrative services on behalf of the trust, for which MV Partners will be paid an annual fee of $60,000, increasing at 4% per year beginning in January 2007. See "Computation of Net Proceeds" and "Description of the Trust Agreement."

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, 2005, and for the nine-month periods ended September 30, 2005 and 2006. 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.

The following table sets forth a projection of cash distributions to holders of trust units who own trust units as of the record date for the distribution related to oil, natural gas and natural gas liquid production for the first quarter of 2007 and continue to own those trust units through the record date for the cash distribution payable with respect to oil, natural gas and natural gas liquid production for the last quarter of 2007. The table also reflects the methodology for calculating the projected cash distribution. The cash distribution projections were prepared by MV Partners for the twelve months ending December 31, 2007, on an accrual of production basis based on the hypothetical assumptions that are described below and in "Projected Cash Distributions—Significant Assumptions Used to Prepare the Projected Cash Distributions."

MV Partners does not as a matter of course make public projections as to future sales, earnings or other results. However, the management of MV Partners has prepared the projected financial information set forth below to present the projected cash distributions to the holders of the trust units based on the estimates and hypothetical assumptions described below. The accompanying unaudited projected financial information was generally prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants, which we refer to as the "AICPA." The preparation of the projected financial information diverged from the AICPA's guidelines, however, in that the AICPA recommends that projected financial information not be presented to persons who do not have the opportunity to negotiate directly with the preparer of such information.

In the view of MV Partners' management, the accompanying unaudited projected financial information was prepared on a reasonable basis and reflects the best currently available estimates and judgments of MV Partners related to oil, natural gas and natural gas liquid production, operating expenses and capital expenses, based on:

The projected financial information was also based on the hypothetical assumption that prices for oil, natural gas and natural gas liquids remain constant during the twelve months ending December 31, 2007, at First Call consensus price forecasts for 2007 as of August 3, 2006, which were $63.04 per Bbl of oil and $8.08 per Mcf of natural gas (which prices exclude the effects of financial hedging arrangements). Because there is no First Call consensus price for natural gas liquids, MV Partners used a hypothetical price equal to approximately 80% of the price used in the projected cash distribution table for oil, which is consistent with the historical pricing realized by MV Partners for natural gas liquids and is the methodology used in the reserve report. These hypothetical prices were adjusted to take into account MV Partners' estimate of the basis differential (based on location and quality of the production) between published prices and the prices actually received by MV Partners. Actual prices paid for oil, natural gas and natural gas liquids expected to be produced from the underlying properties in 2007 will likely differ from these hypothetical prices due to fluctuations in the prices generally experienced with respect to the production of oil, natural gas and natural gas liquids, and such prices may be higher or lower than utilized for purposes of the projected financial information. For example, the published average monthly closing NYMEX crude oil spot price per Bbl was $68.22 for the nine months ended September 30, 2006, with the monthly closing prices ranging from $61.41 to $74.40 during such period. See "Risk Factors—The amounts of the cash distributions by the trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquid prices."

MV Partners utilized these production estimates, hypothetical oil, natural gas and natural gas liquid prices and cost estimates in preparing the projected financial information. This methodology is consistent with the requirements of the SEC for estimating oil, natural gas and natural gas liquid reserves and discounted present value of future net revenues attributable to the net profits interest, other than the use of First Call consensus price forecasts rather than the use of constant prices based on the prices in effect at the time of the reserve estimate as required by the rules and regulations of the SEC. The actual production amounts, commodity prices and costs for 2007, however, are not known for certain, and the projected financial information should not be relied upon as being necessarily indicative of future results. Readers of this prospectus are cautioned not to place undue reliance on the projected financial information.

Neither MV Partners' independent auditors, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the projected financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the projected financial information.

The projections and the estimates and hypothetical assumptions on which they are based are subject to significant uncertainties, many of which are beyond the control of MV Partners or the trust. Actual cash distributions to trust unitholders, therefore, could vary significantly based upon events or conditions occurring that are different from the events or conditions assumed to occur for purposes of these projections. Cash distributions to trust unitholders will be particularly sensitive to fluctuations in oil, natural gas and natural gas liquid prices. See "Risk Factors—The amounts of the cash distributions by the trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquid prices." As a result of typical production declines for oil and natural gas properties, production estimates generally decrease from year to year, and the projected cash distributions shown in the table below are not necessarily indicative of distributions for future years. See "Projected Cash Distributions—Sensitivity of Projected Cash Distributions to Oil, Natural Gas and Natural Gas Liquid Production," which shows projected effects on cash distributions from hypothetical changes in oil production. 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 your original investment. See "Risk Factors—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."

Projected Cash Distributions				Projection for Twelve Months Ending December 31, 2007, Based on Oil, Natural Gas and Natural Gas Liquid Production in Reserve Report
				(dollars in thousands, except per Bbl, Mcf and per unit amounts)
Underlying Properties sales volumes:
	Oil (MBbls)				1,104.0
	Natural gas (MMcf)				131.5
	Natural gas liquids (MBbls)				8.6
Assumed sales price:
	Oil (per Bbl)			$	58.74
	Natural gas (per Mcf)			$	6.85
	Natural gas liquids (per Bbl)			$	46.84
Calculation of net proceeds:
	Gross proceeds:
		Oil sales		$	64,846
		Natural gas sales			901
		Natural gas liquid sales			405
		Payments made to settle hedge contracts			(908	)

			Total	$	65,244

	Costs:
		Lease operating expenses		$	11,727
		Lease maintenance and development expenses			5,135
		Lease overhead expenses			2,239
		Production and property taxes			2,477

			Total	$	21,578

Net proceeds				$	43,666

Percentage allocable to net profits interest					80	%
Net proceeds to trust from net profits interest				$	34,933

Amounts payable to MV Partners to settle hedge contracts				$	550
Percentage allocable to trust					80	%
Payments to trust from hedge contracts					440

Total cash proceeds to trust					35,373

Trust administrative expenses					662

Projected cash distribution on trust units				$	34,711

Projected cash distribution per trust unit(1)				$	3.02

For more information about the estimates and hypothetical assumptions made in preparing the table above, see "Projected Cash Distributions—Significant Assumptions Used to Prepare the Projected Cash Distributions."

Investing in these trust units differs from investing in corporate common stock because:

The amounts of the 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:

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

Recent oil prices have been high compared to historical prices. For example, the NYMEX crude oil spot prices per Bbl were $31.20, $32.55, $43.46 and $61.04 as of December 31, 2002, 2003, 2004 and 2005, respectively, and were $62.91 as of September 30, 2006.

MV Partners has entered into hedge contracts relating to a portion of the oil volumes expected to be produced from the underlying properties, and will assign to the trust the right to receive 80% of the proceeds from these contracts. These hedge contracts, however, do not cover all of the oil volumes that are expected to be produced during the term of the trust. Furthermore, 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 will prohibit MV Partners from entering into new hedging arrangements following the completion of this offering. As a result, the amounts of the cash distributions may fluctuate significantly after 2010 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. In addition, the hedge contracts are subject to counterparty nonperformance and other risks. For a discussion of the hedge contracts, see "The Underlying Properties—Hedge and Derivative Contracts."

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 higher prices. Because the underlying properties are mature, with many of them being in production since the early 1900's, decreases in commodity prices could have a more significant effect on the economic viability of these properties as compared to more recently discovered properties. The commodity price sensitivity of these mature wells is due to a culmination of factors that vary from well-to-well, including the additional costs associated with water handling and disposal, chemicals, surface equipment maintenance, downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result, the volatility of commodity prices may cause the

amount of future cash distributions to trust unitholders to fluctuate, and a substantial decline in the price of oil, natural gas or natural gas liquids will 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:

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 "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 will depend upon, among other things, oil, natural gas and natural gas liquid production and prices and 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 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.

The trust and the public trust unitholders will have no voting or managerial rights with respect to MV Partners, the operator of the underlying properties. As a result, public trust unitholders will 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 properties comprising 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. Also, the public trust unitholders have no voting rights with respect to MV Partners and, therefore, will 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 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.

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 approximately 65 development wells and conduct recompletion and workover operations on existing wells included in the underlying properties. See "The Underlying Properties—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 will 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 will not be 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 "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 prospectus. 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 and proceeds, if any, received by MV Partners upon settlement of the hedge contracts. The reserves attributable to the underlying properties are depleting assets, which means that the reserves attributable to the underlying properties will decline over time. 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 3.5% over the next 20 years assuming no additional development drilling or other capital expenditures are made after 2010 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 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 will provide that the trust's business activities will be 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 will not be permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets and production attributable to the 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, costs and payments made with respect to the hedge contracts, 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 and any costs or payments associated with the hedge contracts, capital expenditures or post-production costs will be 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 "The Underlying Properties." 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.

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

The two members of MV Partners will own approximately 35% of the trust units after this offering, or 25% if the underwriters' option to purchase additional trust units is exercised in full. 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:

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. See "Selling Trust Unitholders." MV Partners and its members have entered into lock-up agreements that prohibit them from selling any trust units for a period of 180 days after the date of this prospectus without the consent of Raymond James &

Associates, Inc., acting as representative of the several underwriters. See "Underwriting." In connection with the closing of this offering, MV Partners and the trust intend to enter into a registration rights agreement pursuant to which the trust will agree 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 "Trust Units Eligible for Future Sale—Registration Rights."

There has been no public market for the trust units and no independent appraisal of the value of the net profits interest has been performed.

The number of trust units to be delivered to MV Partners in exchange for the net profits interest and the initial public offering price of the trust units will be determined by negotiation among MV Partners and the underwriters. Among the factors to be considered in determining such number of trust units and the initial public offering price, in addition to prevailing market conditions, will be current and historical oil and natural gas prices, current and prospective conditions in the supply and demand for oil and natural gas, reserve and production quantities estimated for the net profits interest and the trust's estimated cash distributions. None of MV Partners, the trust or the underwriters will obtain any independent appraisal or other opinion of the value of the net profits interest other than the reserve report prepared by Cawley, Gillespie & Associates, Inc.

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

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 described in "Description of the Trust Agreement," 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 will be managed by the trustee. The voting rights of a trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for an annual or other periodic re-election of the trustee. The trust agreement provides that the trustee may only be removed and replaced by 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. Immediately following the closing of this offering, MV Energy and VAP-I will collectively own approximately 35% of the outstanding trust units (or approximately 25% if the underwriters exercise in full their option to purchase up to an additional 1,125,000 trust units from the members of MV Partners). 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 profits interest. If the trustee does not take appropriate action to enforce provisions of the conveyance, your recourse as a trust unitholder would be limited to bringing a lawsuit against the trustee to compel the trustee to take specified actions. The trust agreement expressly limits the trust unitholders' ability to directly sue 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 will be entitled to the same limitation of personal liability extended to stockholders of private corporations under the General Corporation Law of the State of Delaware. Courts in jurisdictions outside of Delaware, however, may not give effect to such limitation.

The operations of the properties comprising 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 properties comprising 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 properties comprising 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 "The Underlying Properties—Environmental Matters and Regulation" for more information.

The operations of the properties comprising 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 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 "The Underlying Properties—Environmental Matters and Regulation."

The trust has not requested a ruling from the IRS regarding the tax treatment of ownership of the trust units, and MV Partners is not aware of any trust units or similar securities issued by other issuers that are subject to the same tax treatment expected to be accorded to the trust units. If the IRS were to determine (and be sustained in that determination) that the trust is not a "grantor trust" for federal income tax purposes, or that the net profits interest is not a debt instrument for federal income tax purposes, the trust unitholders may receive different and less advantageous tax treatment from that described in this prospectus.

If the net profits interest were not treated as a debt instrument, the deductions allowed to an individual trust unitholder in their recovery of basis in the net profits interest may be itemized

deductions, the deductibility of which would be subject to limitations that may or may not apply depending upon the unitholder's circumstances. See "Federal Income Tax Consequences."

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 you that such a ruling would be granted if requested or that the IRS will not challenge this position on audit.

MV Partners is not aware of any trust units or similar securities representing interests in an entity treated as a grantor trust for federal income tax purposes where the entity holds as its principal asset a production payment treated for federal income tax purposes as a debt instrument that is subject to the current final Treasury regulations governing contingent payment debt instruments. See "Federal Income Tax Consequences." Thus, MV Partners does not believe that there are trust units or similar securities issued by other issuers that receive the same tax treatment expected to be accorded to the trust units.

Trust unitholders should be aware of the possible state tax implications of owning trust units. See "State Tax Considerations."

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 will record 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 believes that the delivery and recording of the conveyance will constitute fully conveyed and vested property interests in the trust under Kansas law. If in a bankruptcy proceeding in which 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 fully conveyed property interests 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, but Colorado courts have not directly determined whether a net profits interest is a real or a personal property interest. MV Partners believes that it is possible that the net profits interest may not be treated as a real property interest under the laws of Colorado. MV Partners intends to record the conveyance of the net profits interest in the real property records of Colorado in accordance with local recording acts. 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 will be 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 will be obligated to market, or cause to be

marketed, the production related to the underlying properties. In addition, MV Partners is obligated to convey to the trust 80% of all proceeds it receives upon settlement of the hedge contracts.

MV Partners has entered into hedge contracts with institutional counterparties, consisting of swap contracts and costless collar arrangements, to reduce the exposure of the revenue from oil production from the underlying properties to fluctuations in crude oil prices in order to achieve more predictable cash flow. The crude oil swap contracts and costless collar arrangements will settle based on the average of the settlement price for each commodity business day in the contract month. In a swap transaction, the counterparty is required to make a payment to MV Partners for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. MV Partners is required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the settlement price is above the fixed price. In a collar arrangement, the counterparty is required to make a payment to MV Partners for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. MV Partners is required to make a payment to the counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price. For a detailed description of the terms of these hedge contracts, please read "The Underlying Properties—Hedge and Derivative Contracts."

The ability of MV Partners to perform its obligations related to the operation of the underlying properties, its obligations to counterparties related to the hedge contracts and its obligations to the trust with respect to the hedge contracts 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 and upon financial, business and other factors, many of which are beyond the control of MV Partners. If the obligation of MV Partners to convey 80% of the proceeds it receives upon settlement of the hedge contracts were not assumed in a bankruptcy proceeding involving MV Partners, the trust would not be entitled to receive future payments from MV Partners from the settlement of the hedge contracts. See "MV Partners" and "Information About MV Partners" in this prospectus for additional information relating to MV Partners, including information relating to the business of MV Partners, historical financial statements of MV Partners and other financial information relating to MV Partners.

The trust's receipt of payments based on the hedge contracts depends upon the financial position of the hedge contract counterparties. A default by any of the hedge contract counterparties could reduce the amount of cash available for distribution to the trust unitholders.

In the event that any of the counterparties to the hedge contracts default on their obligations to make payments to MV Partners and the trust under the hedge contracts, the cash distributions to the trust unitholders would likely be materially reduced as the hedge payments are intended to provide additional cash to the trust during periods of lower crude oil prices.

This prospectus contains forward-looking statements about MV Partners and the trust that are subject to risks and uncertainties. All statements other than statements of historical fact included in this document, including, without limitation, statements under "Prospectus Summary" 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 made in this prospectus under "Projected Cash Distributions," statements pertaining to future development activities and costs, and other statements in this prospectus 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 prospectus, 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:

This prospectus 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.

Immediately prior to the closing of this offering, MV Partners will contribute the net profits interest to the trust in exchange for all of the outstanding trust units. MV Partners will pay underwriting discounts and expenses of approximately $12.0 million associated with this offering and will receive all net proceeds from the offering. The estimated net proceeds to MV Partners will be approximately $138.0 million, assuming an offering price of $20.00 per trust unit. MV Energy and VAP-I will each receive $10.5 million if the underwriters exercise their option to purchase additional trust units in full. MV Partners intends to apply the net proceeds from this offering to repay approximately $58.0 million of indebtedness of MV Partners under its bank credit facility and to use the remaining $80.0 million to repurchase certain equity interests in VAP-I, the owner of a 50% interest in MV Partners, for distributions to the members of MV Partners or any combination of the foregoing. As of September 30, 2006, MV Partners' bank credit facility bore interest at 6.6% per annum and matures on December 19, 2008.

MV Partners is a privately-held limited liability company engaged in the development and production of established oil and natural gas properties in the Mid-Continent region that are primarily located in Kansas. MV Partners was formed in August 2006 as a result of the conversion of MV Partners, LP to a limited liability company. MV Partners, LP was formed in 1998 to acquire oil and natural gas properties and related assets that were located in Kansas and eastern Colorado from a major oil and gas company. These properties constitute the substantial portion of the underlying properties. MV Partners acquired the remainder of the underlying properties in 1999 from a large independent oil and gas company. MV Energy, which was also formed in 1998, serves as the sole manager of MV Partners and was previously the general partner of MV Partners, LP until its conversion into a limited liability company in August 2006. All of the member interests in MV Partners are owned by MV Energy and VAP-I. MV Partners will sell all of its retained trust units to MV Energy and VAP-I upon the completion of this offering.

The acquisition of the underlying properties by MV Partners was originally financed by a large venture capital group, which served as a limited partner of MV Partners until September 2005. In September 2005, MV Partners used bank financing to make distributions to MV Energy and VAP-I to repurchase the limited partner interests held by that large venture capital group. MV Energy is owned equally by Vess Acquisition Group, L.L.C. and Murfin, Inc.

MV Partners is principally engaged in the development, redevelopment and production of existing wells in established fields, as well as drilling new wells in established fields. The operating agreement of MV Partners requires that it engage only in specified lines of business, including acquiring and maintaining oil and natural gas leases and related mineral interests, producing and marketing oil and natural gas, entering into hedging arrangements and other derivatives and engaging in related activities. The operating agreement further prohibits MV Partners from acquiring gas plants, refining or transportation facilities or engaging in contract drilling. In order to help ensure MV Partners' continued focus on operating and developing the underlying properties in an efficient and cost-effective manner, the parties to the operating agreement have agreed to grant the trust the right to enforce the restrictions contained in this agreement as to which lines of business MV Partners may engage in.

Under the terms of the operating agreement of MV Partners, Vess Oil and Murfin Drilling operate on a contract basis the properties held by MV Partners for which MV Partners is designated as the operator. Murfin Drilling is a wholly owned subsidiary of Murfin, Inc. and Vess Oil is an affiliate of Vess Acquisition Group, L.L.C. Vess Oil and Murfin Drilling collectively manage the operations of approximately 96% of the oil and natural gas properties of MV Partners, based on the discounted present value of estimated future net revenues.

The asset portfolio of MV Partners consists mostly of properties in well-established fields, some of which were discovered as early as 1915. Consequently, production rates from these mature wells have declined significantly since their first discovery as the recoverable oil and natural gas supply has been produced. In order to maximize the value of its assets, MV Partners has successfully undertaken development programs that have reduced the natural decline of the production from these fields. These developing programs have included various developmental drilling and re-entry programs, well workover programs, waterflood programs and recompletion programs that are tailored to realize the exploitation potential of each field. As a result of the development programs instituted by MV Partners, the average annual decline rate of the proved developed producing reserves attributable to the underlying properties since 2000 has been 4.0%.

MV Partners has also utilized modern, commercially available techniques and technologies to more completely develop the reserves attributable to the underlying properties. MV Partners is utilizing 3-D seismic technology to further delineate development well locations based on traditional subsurface mapping. In addition to using 3-D seismic technology, MV Partners is working on other programs to

use developing technology such as its work with the Petroleum Technology Transfer Council concerning the application of gelled polymers in certain reservoirs to increase oil production and reduce water production, its work with the Department of Energy studying the injection of carbon dioxide to recover oil otherwise lost in the production process and gas gun stimulation technology.

In order to allow the trust unitholders to more fully realize the benefits of any capital expenditures made with respect to the underlying properties, 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. See "Computation of Net Proceeds—Net Profits Interest."

Vess Oil is an independent oil and gas operating company and, according to the 2005 Kansas Geological Survey, was the largest operator in the State of Kansas based on volume of oil produced and sold in 2005. From its inception, Vess Oil has focused on acquiring, developing, and managing oil and natural gas properties in Kansas. Initially focused on exploration activities, Vess Oil has for the past ten years concentrated on acquisitions in addition to the development and exploitation of its existing reserve base. Vess Oil currently operates over 1,200 oil, natural gas and service wells located primarily in Kansas, with growing operations in Texas. As of September 30, 2006, Vess Oil employed 15 full time employees, five contract professionals and 40 contract personnel in its Wichita office and in five field and satellite offices.

Murfin Drilling is an independent oil and gas operation company and, according to the 2005 Kansas Geological Survey, was the third-largest operator in the State of Kansas based on volume of oil produced and sold in 2005. A family-owned business originally formed in El Dorado, Kansas in 1926 and incorporated in 1990, Murfin Drilling has expanded in the past 80 years into the greater western Kansas area, southwest Nebraska, eastern Colorado and the Oklahoma Panhandle. Murfin Drilling balances exploration, production management, exploitation and acquisitions with contract drilling and well service operations. Murfin Drilling currently operates approximately 800 producing and service wells nationwide. In addition to being an oil and gas producer and operator, Murfin Drilling also provides oilfield services, including drilling services, well servicing and rig transportation services in western Kansas, southwest Nebraska, southeastern Colorado and the Oklahoma Panhandle. As of September 30, 2006, Murfin Drilling employed approximately 275 employees that work from its headquarters in Wichita, Kansas, or its five field offices in Kansas.

The trust units do not represent interests in, or obligations of, MV Partners.

The summary financial data presented below should be read in conjunction with the audited financial statements and the unaudited interim financial statements of MV Partners and the related notes and "Management's Discussion and Analysis of Financial Condition and Results of Operations of MV Partners" included elsewhere in this prospectus. The following summary financial data of MV Partners as of December 31, 2003, 2004 and 2005, and for each of the years in the three-year period ended December 31, 2005, have been derived from MV Partners' audited financial statements. The following summary financial data of MV Partners as of September 30, 2006, and for the nine-month periods ended September 30, 2005 and 2006, have been derived from MV Partners' unaudited interim financial statements. The unaudited financial statements were prepared on a basis consistent with the audited statements and, in the opinion of MV Partners, include all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the results of MV Partners for the periods presented.

The summary unaudited pro forma financial data for the year ended December 31, 2005, and as of and for the nine months ended September 30, 2006, set forth in the following table have been derived from the unaudited pro forma financial statements of MV Partners included in this prospectus beginning on page MVF-24. The pro forma adjustments have been prepared as if the offer and sale of the trust units and the application of the net proceeds therefrom had taken place (1) on September 30, 2006, in the case of the pro forma balance sheet information as of September 30, 2006, and (2) as of January 1, 2005, in the case of the pro forma statement of earnings information for the year ended December 31, 2005, and for the nine months ended September 30, 2006.

		Year ended December 31,		Nine months ended September 30,		Pro forma
Historical results		December 31, 2005		September 30, 2006
	2003		2004		2005		2005		2006
		(in thousands)
Revenue		$	28,046		$	31,045		$	36,162	$	25,786	$	35,510	$	16,000	$	13,578
Net earnings (loss)		$	7,090		$	10,341		$	13,125	$	8,788	$	13,638	$	10,530	$	7,749
Total assets (at period end)		$	65,165		$	64,437		$	68,303	$	78,836	$	72,943		N/A	$	51,037
Long-term liabilities, excluding current maturities (at period end)		$	29,484		$	35,176		$	91,793	$	8,279	$	96,483		N/A	$	143,516

During the last quarter of 2005, through a series of transactions in connection with an ownership change, MV Partners refinanced its debt and borrowed an additional $65 million, bringing its total bank borrowings to $90 million on December 21, 2005. The oil and natural gas properties of MV Partners formed the collateral base for its refinancing and its fair market value was sufficient as collateral for the loan facility. The carrying costs of the oil and natural gas properties was not written up as part of this transaction and remain at their historical cost basis, which relates back to their acquisition in 1998. Therefore, the carrying costs of the assets at December 31, 2005 and September 30, 2006 are less than the total liabilities on the historical results above. If the historical costs of the underlying properties were replaced with the estimated current market values, MV Partners believes its total assets as of September 30, 2006 would exceed its total liabilities.

The table below includes selected production and reserve information for MV Partners for the periods presented.

		Year ended December 31,		Nine months ended September 30,
Historical results
	2003		2004		2005		2005		2006
Production (MBoe)		1,219		1,147		1,076		801		787
Net proved reserves (MBoe) (at period end)		15,924		16,176		18,203		N/A		N/A
Net proved developed reserves (MBoe) (at period end)		15,212		15,577		16,136		N/A		N/A

MV Partners does not currently have any executive officers, directors or employees. Instead, MV Partners is managed by an executive management team consisting of certain officers and employees of Vess Oil and Murfin Drilling.

Except as described below, none of the members of the executive management team receive compensation from the trust or MV Partners. Instead, 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, primarily at the field level. The fee is based on a monthly charge per active operated well and is payable to the entity that operates the particular well on behalf of MV Partners. In 2005, the aggregate overhead fee paid to Vess Oil and Murfin Drilling was approximately $2.1 million. The fee is adjusted annually and will increase or decrease each year based on changes in the Overhead Adjustment Index published by the Council of Petroleum Accountants Societies for that year. In addition, MV Partners pays a monthly administrative services fee to MV Energy for certain corporate administrative and accounting services arranged by MV Energy. Most of these services are performed on behalf of MV Energy by Murfin Drilling and, therefore, MV Energy transmits the entire administrative services fee to Murfin Drilling. The fee is currently $5,000 per month and will increase by 4% each year commencing in January 2007. MV Partners, MV Energy, Vess Oil and Murfin Drilling do not separately allocate or accrue compensation expense for the services performed by employees of Vess Oil or Murfin Drilling on behalf of MV Partners or MV Energy, and their compensation from Vess Oil or Murfin Drilling, as the case may be, is not directly related to the services they perform on behalf of MV Partners or MV Energy. Vess Oil and Murfin Drilling are not contractually obligated to provide the corporate administrative and accounting services on behalf of MV Partners or MV Energy other than the operation of the underlying properties, and MV Partners and MV Energy may contract for the provision of the corporate administrative and accounting services from other parties at any time. Furthermore, none of the members of the executive management team are contractually obligated to continue performing services on behalf of MV Partners and neither Vess Oil nor Murfin Drilling are contractually obligated to make their employees available to perform such services.

MV Partners has retained the services of Richard J. Koll, C.P.A., a sole proprietorship of which Richard J. Koll is the sole owner. Mr. Koll also performs the function of Chief Financial Officer on behalf of MV Partners. In addition to Mr. Koll, Richard J. Koll, C.P.A. employs three full-time accountants and two part-time employees, one of whom is an accountant. From January 1, 2006 through November 30, 2006, MV Partners made payments to Richard J. Koll, C.P.A. for fees and expenses of approximately $177,000 in connection with services rendered on behalf of MV Partners. MV Partners expects to pay an additional $85,000 to Richard J. Koll, C.P.A. for fees and expenses in connection with the completion of this offering. MV Partners did not make any payments to Richard J. Koll, C.P.A. prior to January 1, 2006. Payments made to Richard J. Koll, C.P.A. described above will not reduce the amount of cash available for distribution to the trust unitholders.

Set forth in the table below are the names, ages, function performed on behalf of MV Partners and employer of the members of the executive management team of MV Partners:

Name	Age	Function Performed on Behalf of MV Partners	Employer
J. Michael Vess	55	Co-Chief Executive Officer	Vess Oil
David L. Murfin	54	Co-Chief Executive Officer	Murfin Drilling
Richard J. Koll	56	Chief Financial Officer	Vess Oil
William R. Horigan	56	Vice President—Operations	Vess Oil
Brian Gaudreau	51	Vice President—Land	Vess Oil
Jerry Abels	79	Vice President—Land	Murfin Drilling
Robert D. Young	65	Treasurer	Murfin Drilling
Richard W. Green	64	Controller	Murfin Drilling

J. Michael Vess is the President, Chief Executive Officer and principal owner of Vess Oil and is the managing member of Vess Acquisition Group, L.L.C. Mr. Vess co-founded Vess Oil in 1979 and continues to be responsible for the coordination and supervision of exploration and production and the acquisition of its oil and natural gas reserves. Mr. Vess received a Bachelor of Business Administration degree from Wichita State University in 1972 and subsequently received his CPA certificate. Mr. Vess currently serves on the Board of Directors and Executive Committees for the Kansas Independent Oil and Gas Association ("KIOGA") and is the current Chairman of the KIOGA Committee on Electricity. He is also a member of the Interstate Oil and Gas Compact Commission Outreach Committee.

Richard J. Koll serves as the Financial Manager for Vess Oil where he oversees administrative and accounting matters. Mr. Koll has held his current position since 1992. Mr. Koll is not an employee of Vess Oil but performs services on behalf of Vess Oil through Richard J. Koll, C.P.A., a sole proprietorship of which Mr. Koll is the sole owner. Mr. Koll received a Bachelor of Business Administration degree in Accounting from Wichita State University in 1972 and subsequently received his CPA certificate. He is currently the Chairman of the KIOGA Committee on Ad Valorem Taxes and also serves on the Board of Directors and Executive Committee for KIOGA. He is a member of the Kansas Society of Certified Public Accountants and the American Institute of Certified Public Accountants.

William R. Horigan is the Vice President of Operations for Vess Oil where he is responsible for the engineering, enhancement and exploitation of its existing properties as well as the engineering analysis and evaluation of its future reserve acquisitions. Mr. Horigan joined Vess Oil in 1988 as Operations Manager. Prior to joining Vess Oil, Mr. Horigan served in various petroleum engineering capacities for Amoco Production Company beginning in 1975. Mr. Horigan graduated from the University of Kansas in 1974 with a Bachelor of Science degree in Chemical Engineering. Mr. Horigan is a member of the Society of Petroleum Engineers and serves on the Executive Board for the Wichita Section. He is also a member of the Producers Advisory Group and Petroleum Technology Transfer Council of the North Mid-Continent Region.

Brian Gaudreau is the Vice President of Land for Vess Oil where he is responsible for land, contracts and acquisitions. Mr. Gaudreau joined Vess Oil in 2002 as Vice President, Land and Acquisitions. Prior to joining Vess Oil, he held the title of Manager, Land and Acquisitions for Stelbar Oil Corporation, Inc. beginning in 1989. Mr. Gaudreau graduated from the University of Kansas in 1977 with a Bachelors degree in Economics. Mr. Gaudreau belongs to the American Association of Professional Landmen and the Dallas Acquisitions, Divestitures, and Mergers Energy Forum and is the current Secretary of KIOGA.

David L. Murfin is the President of Murfin Drilling and the Chairman and Chief Executive Officer of Murfin, Inc. Mr. Murfin has held his positions at Murfin Drilling and Murfin, Inc. since 1992 and 1998, respectively. Mr. Murfin received degrees in Mechanical Engineering and Business Administration from the University of Kansas in 1975. Mr. Murfin has previously served as National Chairman of the Liaison Committee of Cooperating Oil & Gas Associations, President of the KIOGA, a Regional Vice President of the Texas Independent Producers and Royalty Owners Association, and a member of the Executive Committee of the Board of Directors of the International Association of Drilling Contractors. Mr. Murfin currently serves on the Board of Directors of the Independent Petroleum Association of America and on the National Petroleum Council.

Jerry Abels is Land Manager for Murfin Drilling where he is responsible for land and contracts. Mr. Abels has held his position at Murfin Drilling since 1979. Prior to joining Murfin Drilling, he was involved in his own oilfield equipment and exploration business. Mr. Abels received a degree in Business from the University of Texas in 1951. Mr. Abels is a CPLM, Certified Petroleum Landman, and has served on the National Board of the AAPL, American Association of Petroleum Landmen.

Richard W. Green is the Controller of Murfin Drilling. After receiving his Masters in Science Accounting in 1971 from Wichita State University, Mr. Green spent eight years in public accounting with Peterson, Peterson and Goss CPA's. Mr. Green joined Murfin Drilling as Assistant Controller in 1980.

Robert D. Young is the Treasurer and Chief Financial Officer of Murfin Drilling and the President and Chief Financial Officer of Murfin, Inc. After receiving a Bachelor of Business Administration degree in Accounting from Wichita State University in 1965, Mr. Young began his career in 1965 with Peterson, Peterson and Goss CPA's. Mr. Young joined Murfin Drilling as Controller and financial advisor to the sole owner of the company in 1974. Mr. Young is currently serving on the Board of Directors and is Treasurer of the Petroleum Club of Wichita and is a member of the Kansas Society of Certified Public Accountants and the American Institute of Certified Public Accountants.

The following table sets forth, as of December 1, 2006, the beneficial ownership of interests in MV Partners that will be outstanding upon the consummation of this offering, assuming no exercise of the underwriters' option to purchase additional trust units, and the application of the related net proceeds to be received by MV Partners and held by:

Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all member interests of MV Partners shown as beneficially owned by them.

Name of Beneficial Owner	Percentage of Member Interests Beneficially Owned
MV Energy, LLC(1)	68.7	%
VAP-I, LLC(2)	50.0	%
Vess Acquisition Group, L.L.C.(3)	34.3	%
Murfin, Inc.(4)	35.6	%
J. Michael Vess(5)	34.0	%
David L. Murfin(6)	28.9	%
William R. Horigan	—
Brian Gaudreau	—
Jerry Abels	—
Robert D. Young	—
Richard W. Green	—
Richard J. Koll	—
Executive management team as a group(1)(2)(3)(4)(5)(6)	62.9	%

The trust is a statutory trust created under the Delaware Statutory Trust Act in August 2006. The business and affairs of the trust will be managed by The Bank of New York Trust Company, N.A., as trustee. MV Partners has no ability to manage or influence the operations of the trust. In addition, Wilmington Trust Company will act as Delaware trustee of the trust. The Delaware trustee will have only minimal rights and duties as are necessary to satisfy the requirements of the Delaware Statutory Trust Act. In connection with the completion of this offering, MV Partners will contribute the net profits interest to the trust in exchange for all 11,500,000 of the outstanding trust units. The trust's first quarterly distribution will consist 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, this cash payment will include 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. In addition, in connection with the trust's second quarterly distribution expected to be made on or about April 25, 2007, MV Partners will contribute cash in an amount equal to the amount that would have been payable to the trust as of the closing of this offering had the net profits interest been in effect since January 1, 2007. The cash contribution will also include 80% of all amounts paid to MV Partners from hedge contract counterparties for settlements related to the period from January 1, 2007 to the closing of this offering.

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 as a lender provided the terms of the loan are fair to the trust unitholders. The trustee may also deposit funds awaiting distribution in an account with itself, if the interest paid to the trust at least equals amounts paid by the trustee on similar deposits, and make other short-term investments with the funds distributed to the trust.

The trust will pay the trustee an administrative fee of $150,000 per year. The trust will pay the Delaware trustee a fee of $2,500 per year. The trust will also incur legal, accounting, tax and engineering fees, printing costs and other expenses that are deducted by the trust before distributions are made to trust unitholders. Total administrative expenses of the trust on an annualized basis for 2006 are initially expected to be approximately $660,000, including the administrative services fee payable to MV Partners.

In connection with the closing of this offering, the trust will enter into an administrative services agreement with MV Partners that obligates the trust, throughout the term of the trust, to pay to MV Partners each quarter an administrative services fee for accounting, bookkeeping and informational services to be performed by MV Partners on behalf of the trust relating to the net profits interest. The annual fee, payable in equal quarterly installments, will total $60,000 in 2006 and will increase by 4% each year beginning in January 2007. The administrative services agreement will terminate upon the termination of the net profits interest unless earlier terminated by mutual agreement of the trustee and MV Partners.

Immediately prior to the closing of this offering, MV Partners will create the term net profits interest through a conveyance to the trust of a term net profits interest carved from MV Partners' interests in all of its oil and natural gas properties, which properties are located in the Mid-Continent region in the States of Kansas and Colorado. The net profits interest will entitle the trust to receive 80% of the net proceeds from the sale of production of oil, natural gas and natural gas liquids attributable to the underlying properties 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 amount of trust revenues and cash distributions to trust unitholders will depend on, among other things:

The following table sets forth a projection of cash distributions to holders of trust units who own trust units as of the record date for the distribution related to oil, natural gas and natural gas liquid production for the first quarter of 2007 and continue to own those trust units through the record date for the cash distribution payable with respect to oil, natural gas and natural gas liquid production for the last quarter of 2007. The table also reflects the methodology for calculating the projected cash distribution. The cash distribution projections were prepared by MV Partners for twelve months ending December 31, 2007, on an accrual of production basis based on the hypothetical assumptions that are described in "—Significant Assumptions Used to Prepare the Projected Cash Distributions."

MV Partners does not as a matter of course make public projections as to future sales, earnings or other results. However, the management of MV Partners has prepared the projected financial information set forth below to present the projected cash distributions to the holders of the trust units based on the estimates and hypothetical assumptions described below. The accompanying unaudited projected financial information was generally prepared with a view toward complying with the guidelines established by the AICPA. The preparation of the projected financial information diverged from the AICPA's guidelines, however, in that the AICPA recommends that projected financial information not be presented to persons who do not have the opportunity to negotiate directly with the preparer of such information.

The projected financial information was also based on the hypothetical assumption that prices for oil, natural gas and natural gas liquids remain constant during the twelve months ending December 31, 2007, and at First Call consensus price forecasts for 2007 as of August 3, 2006, which were $63.04 per Bbl of oil and $8.08 per Mcf of natural gas (which prices exclude the effects of financial hedging arrangements). Because there is no First Call consensus price for natural gas liquids, MV Partners used a hypothetical price equal to approximately 80% of the hypothetical price used in the projected cash distribution table for oil, which is consistent with the historical pricing realized by MV Partners for natural gas liquids and is the methodology used in the reserve report. These hypothetical prices were adjusted to take into account MV Partners' estimate of the basis differential (based on location and quality of the production) between published prices and the prices actually received by MV Partners. These hypothetical prices are the prices utilized for purposes of preparing the reserve report in accordance with the requirements of the SEC. Actual prices paid for oil, natural gas and natural gas liquids expected to be produced from the underlying properties in 2007 will likely differ from these hypothetical prices due to fluctuations in the prices generally experienced with respect to the production of oil, natural gas and natural gas liquids, and such prices may be higher or lower than utilized for purposes of the projected financial information. For example, the published average monthly closing NYMEX crude oil spot price per Bbl was $68.22 for the nine months ended September 30, 2006, with the monthly closing prices ranging from $61.41 to $74.40 during such period. See "Risk Factors—The amounts of the cash distributions by the trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquid prices."

The projections and the estimates and hypothetical assumptions on which they are based are subject to significant uncertainties, many of which are beyond the control of MV Partners or the trust. Actual cash distributions to trust unitholders, therefore, could vary significantly based upon events or conditions occurring that are different from the events or conditions assumed to occur for purposes of these projections. Cash distributions to trust unitholders will be particularly sensitive to fluctuations in oil, natural gas and natural gas liquid prices. See "Risk Factors—The amounts of the cash distributions by the trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas liquid prices." As a result of typical production declines for oil and natural gas properties, production estimates generally decrease from year to year, and the projected cash distributions shown in the table below are not necessarily indicative of distributions for future years. See "—Sensitivity of Projected Cash Distributions to Oil, Natural Gas and Natural Gas Liquid Production," which shows projected effects on cash distributions from hypothetical changes in oil production. 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 your original investment. See "Risk Factors—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."

Projected Cash Distributions				Projection for Twelve Months Ending December 31, 2007, Based on Oil, Natural Gas and Natural Gas Liquid Production in Reserve Report(2)
				(dollars in thousands, except per Bbl, Mcf and trust unit amounts)
Underlying properties sales volumes:
	Oil (MBbls)				1,104.0
	Natural gas (MMcf)				131.5
	Natural gas liquids (MBbls)				8.6
Assumed sales price:
	Oil (per Bbl)			$	58.74
	Natural gas (per Mcf)			$	6.85
	Natural gas liquids (per Bbl)			$	46.84
Calculation of net proceeds:
	Gross proceeds:
		Oil sales		$	64,846
		Natural gas sales			901
		Natural gas liquid sales			405
		Payments made to settle hedge contracts			(908	)

			Total	$	65,244

	Costs:
		Lease operating expenses		$	11,727
		Lease maintenance and development expenses			5,135
		Lease overhead expenses			2,239
		Production and property taxes			2,477

			Total	$	21,578

Net proceeds				$	43,666

Percentage allocable to net profits interest					80	%
Net proceeds to trust from net profits interest				$	34,933

Amounts payable to MV Partners to settle hedge contracts				$	550
Percentage allocable to trust					80	%
Payments to trust from hedge contracts					440

Total cash proceeds to trust					35,373

Trust administrative expenses					662

Projected cash distribution on trust units				$	34,711

Projected cash distribution per trust unit(1)				$	3.02

Sensitivity of Projected Cash Distributions to Oil, Natural Gas and Natural Gas Liquid Production

The amount of revenues of the trust and cash distributions to the trust unitholders will be directly dependent on the sales price for oil, natural gas and natural gas liquid production sold from the underlying properties, the volumes of oil, natural gas and natural gas liquids produced attributable to the underlying properties, payments made under the hedge contracts and, to some degree, the level of variations in lease operating expenses, lease maintenance and development expenses, lease overhead expenses and production and property taxes. The increase in the projected cash distributions in the twelve months ending December 31, 2007 compared to the amount of cash that would have been available for distribution in the year ended December 31, 2005 is primarily because of an expected decrease in hedge settlement costs and an expected increase in production from 2005 to 2007. The table below demonstrates the projected effect that hypothetical changes in the estimated oil production for 2007, as reflected in the reserve report, could have on cash distributions to the trust unitholders.

The table and discussion below sets forth sensitivity analyses of annual cash distributions per trust unit for the twelve months ending December 31, 2007, on the accrual basis, on the assumption that a trust unitholder purchased a trust unit on January 1, 2007, and held such trust unit until the quarterly record date for distributions made with respect to oil, natural gas and natural gas liquid production in the last quarter of 2007, based upon (1) the assumption that a total of 11,500,000 trust units are issued and outstanding after the closing of the offering made hereby; (2) an assumed purchase price of $20.00 per trust unit; (3) various realizations of production levels estimated in the reserve report; (4) the hypothetical commodity prices based upon First Call consensus price forecasts for oil and natural gas as of August 3, 2006; (5) the impact of the hedge contracts entered into by MV Partners that relate to production from the underlying properties; and (6) other assumptions described below under "—Significant Assumptions Used to Prepare the Projected Cash Distributions." The hypothetical commodity prices of oil, natural gas and natural gas liquid production shown have been chosen solely for illustrative purposes. For a description of the effect of calculating annual cash distributions on an accrual basis rather than on a cash basis as prescribed in the conveyance of the net profits interest, see "—Significant Assumptions Used to Prepare the Projected Cash Distributions—Timing of Actual Distributions."

The table below is not a projection or forecast of the actual or estimated results from an investment in the trust units. The purpose of the table below is to illustrate the sensitivity of cash distributions to changes in oil production levels. There is no assurance that the hypothetical assumptions described below will actually occur or that production levels will not change by amounts different from those shown in the tables.

MV Partners has entered into certain hedge contracts related to the oil production from the underlying properties for the years 2006 through 2010. For the years 2006, 2007 and 2008, MV Partners has entered into swap contracts and costless collars at prices ranging from $56 to $68 per barrel of oil that hedge approximately 82% to 86% of expected production from the proved developed producing reserves attributable to the underlying properties in the reserve report. For the years 2009 and 2010, MV Partners has entered into swap contracts at prices ranging from $63 to $71 per barrel of oil that hedge approximately 80% of expected production from the proved developed producing reserves attributable to the underlying properties in the reserve report. As a result, cash distributions related to 2006, 2007 and 2008 are not expected to fluctuate significantly due to changes in oil prices, and fluctuations in cash distributions related to 2009 and 2010 as a result of changes in oil prices will not be as significant as they would be if the hedge contracts were not in place. MV Partners has not entered into any hedge contracts related to production from the underlying properties for periods after 2010 and, therefore, cash distributions for those periods are expected to fluctuate significantly as a result of changes in oil prices after 2010. See "Risk Factors" for a discussion of various items that could impact production levels and the prices of oil and natural gas.

The purpose of the table below is to illustrate the sensitivity of cash distributions solely to changes in oil production levels, excluding the impact of any price differences for production of oil from the prices forecasted. The table below is not a projection or forecast of the actual or estimated results from an investment in the trust units.

Sensitivity of Total 2007 Projected Cash Distributions Per Trust Unit
to Changes in Oil Production

Percentage of 2007 Estimated Oil Production(1)	Total 2007 Projected Cash Distributions Per Trust Unit
90%	$	2.57
95%	$	2.79
100%	$	3.02
105%	$	3.24
110%	$	3.47

Due to the significant hedging in place with respect to estimated 2007 oil production, no sensitivity analysis is presented to reflect the sensitivity of changes in oil prices on the level of cash distributions to unitholders. In addition, because estimated production for 2007 is expected to consist of approximately 98% oil and 2% natural gas and natural gas liquids, no sensitivity analysis is presented to reflect the sensitivity of changes in production or prices of natural gas or natural gas liquids on the level of cash distributions to unitholders.

Timing of Actual Distributions. In preparing the projected cash distributions and sensitivity analysis above, the revenues and expenses of the trust were calculated based on the terms of the conveyance creating the trust's net profits interest. These calculations are described under "Computation of Net Proceeds—Net Profits Interest," except that amounts for the projection and table above were calculated on an accrual or production basis rather than the cash basis prescribed by the conveyance. As a result, the proceeds for production for a portion of the three months ended December 31, 2007, and reflected in the projection and sensitivity analysis, will actually enter into the calculation of net proceeds to be received by the trust in 2008. Net proceeds from production during the five months ended December 31, 2006, will in fact be distributed to the trust in 2007.

Production Estimates. Production estimates for 2007 are based on the reserve report. The reserve report assumed constant prices at June 30, 2006, based on a crude oil price of $73.93 ($70.68 realized) per Bbl, the weighted average wellhead natural gas price at June 30, 2006, of $5.07 per Mcf and the natural gas liquid price at June 30, 2006, of $56.37 per Bbl. Production from the underlying properties for 2007 is estimated to be 1,104.0 MBbls of oil, 131.5 MMcf of natural gas and 8.6 MBbls of natural gas liquids. See "—Oil, Natural Gas and Natural Gas Liquid Prices" below for a description of changes in production due to price variations. Net sales for the nine months ended September 30, 2006, on an accrual basis, were 771 MBbls of oil, 76 MMcf of natural gas and 5 MBbl of natural gas liquids. Net sales for the year ended December 31, 2005, on an accrual basis, were 1,058 MBbls of oil, 89 MMcf of natural gas and 5 MBbls of natural gas liquids. The projected increase of estimated production for 2007 is primarily the result of approximately $3.4 million of maintenance and development expenditures on the underlying properties that either have been or are planned to be incurred by MV Partners during the second half of 2006 for well workover and other development activities that are expected to

increase production from the underlying properties beginning in late 2006 and through 2007. In addition, MV Partners expects to incur approximately $5.1 million of maintenance and development expenditures during 2007 to further increase production from the underlying properties in 2007. Although MV Partners expects annual production from the underlying properties to decline at an average annual rate of 3.5% over the next 20 years, MV Partners expects the actual annual decline rate to be smaller during the beginning of that period and to increase over the course of that period. The expected increase in the annual decline rate over the course of this 20-year period is primarily a result of the assumption that no additional development drilling or other capital expenditures are made after 2010 on the underlying properties. Differing levels of production will result in different levels of distributions and cash returns.

Oil, Natural Gas and Natural Gas Liquid Prices. Hypothetical oil and natural gas prices assumed in the projected cash distribution table are based on published First Call consensus forecasts of oil and natural gas prices for 2007 as of August 3, 2006. Published NYMEX benchmark prices for crude oil are based upon an assumed light, sweet crude oil of a particular gravity that is stored in Cushing, Oklahoma while published NYMEX benchmark prices for natural gas are based upon delivery at the Henry Hub in Louisiana. These prices differ from the average or actual price received for production attributable to the underlying properties. Differentials between published oil and natural gas prices and the prices actually received for the oil and natural gas production may vary significantly due to market conditions, transportation costs and other factors.

In the above tables, $4.31 per barrel is deducted from the First Call consensus forecast price for crude oil in 2007 to reflect these differentials. This deduction is based on MV Partners' estimate of the average difference between the NYMEX published price of crude oil and the price to be received by MV Partners for production attributable to the underlying properties during 2007. The average difference between the NYMEX published price of crude oil and the price received by MV Partners for oil production attributable to the underlying properties during the month of June 2006 was $3.25 per barrel, which is the assumed differential used in the reserve report. Pro forma average oil prices appearing in this prospectus have been adjusted for these differentials.

In the cash distribution table, $1.23 is deducted from the First Call consensus forecast price for natural gas in 2007 to reflect these differentials. This deduction is based on MV Partners' estimate of the average difference between the NYMEX published price of natural gas and the price to be received by MV Partners for production attributable to the underlying properties during 2007. The average difference between the NYMEX published price of natural gas and the price received by MV Partners for natural gas production attributable to the underlying properties during the six months ended June 30, 2006 was $1.73 per Mcf. Because there is no First Call consensus price for natural gas liquids, MV Partners used a hypothetical price equal to approximately 80% of the hypothetical price used in the projected cash distribution table for oil, which is consistent with the historical pricing realized by MV Partners for natural gas liquids and is the methodology used in the reserve report.

The adjustments to published oil, natural gas and natural gas liquid prices applied in the above projected cash distribution estimate are based upon an analysis by MV Partners of the historic price differentials for production from the underlying properties with consideration given to gravity, quality and transportation and marketing costs that may affect these differentials in 2007. There is no assurance that these assumed differentials will occur in 2007.

When oil, natural gas and natural gas liquid prices decline, the operators of the properties comprising the underlying properties may elect to reduce or completely suspend production. No adjustments have been made to estimated 2007 production to reflect potential reductions or suspensions of production.

Settlements of Hedge Contracts. The projected gross proceeds includes the impact of payments that would be made to settle the hedge contracts in 2007 based upon the hypothetical oil prices

assumed in the projected cash distribution table. In addition, the cash distribution table includes the impact of the trust's right to receive 80% of the amounts payable to MV Partners from hedge contract counterparties upon monthly settlements of the hedge contracts. MV Partners has entered into swap contracts with respect to 687,000 Bbls of oil expected to be produced from the underlying properties during 2007 at a weighted average price per Bbl of $62.52 and has entered into costless collars with respect to 120,000 Bbls of oil expected to be produced from the underlying properties during 2007 at a weighted average floor and ceiling price of $61.00 and $68.00, respectively.

During the year ended December 31, 2005, MV Partners incurred costs of approximately $22 million as a result of the settlement of hedging arrangements. Because of the price at which these hedging arrangements settled compared to the market price of crude oil, the excess of revenues over direct operating expenses for the underlying properties during the year ended December 31, 2005 was significantly decreased from what it otherwise would have been had these hedging arrangements not been in place. Using the hypothetical oil prices in the projected cash distributions table above, the projected cash distributions include an estimated cost of $358,000 related to hedge settlements in 2007. This estimated decrease in hedge settlement costs between 2005 and 2007 is the primary reason for the increase in projected cash distributions between 2005 and 2007.

Costs. For 2007, MV Partners estimates lease operating expenses to be $11.7 million, lease maintenance and development expenses to be $5.1 million, lease overhead expenses to be $2.2 million and production and property taxes to be $2.5 million. For the nine months ended September 30, 2006, lease operating expenses were $8.7 million, lease maintenance and development expenses were $2.8 million, lease overhead expenses were $1.7 million and production and property taxes were $2.8 million. Lease overhead is the estimated fee for all properties operated by MV Partners that is deducted by MV Partners in calculating net proceeds. For a description of production expenses and development costs, see "Computation of Net Proceeds—Net Profits Interest." MV Partners expects its costs in 2007 to be substantially the same as its expected costs in 2006 after giving effect to capital projects expected to be undertaken during the third and fourth quarters of 2006.

Administrative Expense. Trust administrative expense for 2007 is assumed to be $662,000. See "The Trust."

The underlying properties consist of MV Partners' net interests in all of its oil and natural gas properties as of the date of the conveyance of the net profits interest to the trust, which properties are located in the Mid-Continent region in the States of Kansas and Colorado. These oil and natural gas properties consist of approximately 985 producing oil and natural gas wells on approximately 202 leases. 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 natural gas company. As of June 30, 2006, proved reserves attributable to the underlying properties, as estimated in the reserve report, were approximately 18.7 MMBoe with a PV-10 of $358.7 million. During the nine months ended September 30, 2006, average net daily production from the underlying properties was 2,883 Boe per day. Affiliates of MV Partners are currently the operators or contract operators of substantially all of the properties comprising the underlying properties.

MV Partners' interests in the properties comprising 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 properties comprising 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 the landowner's 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 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.

MV Partners' interest in the underlying properties after deducting the net profits interest entitles it to 20% 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 and all of the net proceeds thereafter. Immediately following the closing of this offering, MV Partners intends to sell at the initial public offering price the 4,000,000 trust units not sold in this offering to its two members, MV Energy and VAP-I, in exchange for cash in the amount of $8.0 million and promissory notes. Each of MV Energy and VAP-I will own 50% of the retained units. These retained trust units are subject to lock-up arrangements. See "Trust Units Eligible for Future Sale—Lock-up Agreements." MV Partners believes that its members' retained ownership interests will provide sufficient incentive for MV Partners to operate (or cause to be operated) and develop the oil and natural gas properties comprising the underlying properties in an efficient and cost-effective manner. In addition, MV Partners has agreed to use commercially reasonable efforts to cause the operators of the underlying properties to operate these properties in the same manner it would if these properties were not burdened by 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. Based on the reserve report, annual production from the underlying properties is expected to decline at an average annual rate of 3.5% over the next 20 years assuming no additional development drilling or other capital expenditures are made after 2010 on the underlying properties. MV Partners expects total capital expenditures for the underlying properties during the next five years will be approximately $17 million, which it expects will partially offset the natural decline in production otherwise expected to occur with respect to the underlying properties as described in more detail below.

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, 2005, and for the nine-month periods ended September 30, 2005 and 2006, derived from the underlying properties' audited and unaudited statements of historical revenues and direct operating expenses included elsewhere in this prospectus. The unaudited statements were prepared on a basis consistent with the audited statements and, in the opinion of MV Partners, include all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the revenues, direct operating expenses and the excess of revenues over direct operating expenses relating to the underlying properties for the periods presented.

will not impact the amount of cash available for distribution to the trust. The settlement prices of the existing hedge contracts range from $56 to $71 and are more consistent with current crude oil prices.

Excess of revenues over direct operating expenses for the underlying properties was $20.5 million for the nine months ended September 30, 2006, compared to $13.0 million for the nine months ended September 30, 2005. The increase was primarily a result of an increase in the average price received for the oil and natural gas sold. This was partially offset by an increase in direct operating expenses and a decrease in hedge and other derivative expense.

Revenues. Revenues from oil, natural gas and natural gas liquid sales increased $8.2 million between the periods. This increase in revenues was primarily the result of an increase in the average price received for crude oil sold from $53.25 per Bbl for the nine months ended September 30, 2005 to $64.91 per Bbl for the nine months ended September 30, 2006. The increase in revenues was also the result of a small decrease in the average price received for natural gas sold from $5.86 per Mcf for the nine months ended September 30, 2005 to $5.68 per Mcf for the nine months ended September 30, 2006, as well as a small increase in volumes sold.

Hedge and other derivative activity. Hedge and other derivative activity expense decreased from $16.8 million for the nine months ended September 30, 2005 to $15.5 million for the nine months ended September 30, 2006. This decrease was due to an increase in ineffectiveness of hedges and other derivatives then in place being recorded to the expense account and a decrease in realized hedge losses for the period.

At September 30, 2006, MV Partners recorded a $1.2 million expense for ineffectiveness of hedges and other derivatives compared to a $0.3 million expense at September 30, 2005. The increase in ineffectiveness during the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 is partially the result of additional hedge and other derivative contracts placed during the last quarter of 2005. At September 30, 2005, MV Partners had open swap agreements covering the next 15 months and no open collar transactions. At September 30, 2006, MV Partners had

open swap agreements covering the next 51 month periods and an open collar transaction covering the 12 months of 2007 which increased the volume of hedges and the exposure to hedge ineffectiveness compared to September 30, 2005. The change in value of the open collar transaction resulted in an expense of $0.3 million for the nine months ended September 30, 2006.

Hedge ineffectiveness of the swap agreements is the result of various factors including changes in the average crude oil price and changes in the basis differential between the NYMEX price and the price actually received by MV Partners. An increase in the basis differential, the increase in the price of crude oil and the extended hedge and derivative contracts all combined to increase the expense associated with the swap agreements for the nine months ended September 30, 2006 by $0.9 million.

In addition, a portion of the increase in hedge and other derivative expense was due to the higher average NYMEX price per Bbl of crude oil for the first nine months of 2006 of $68.22 compared to $55.40 for the first nine months of 2005. The weighted average settlement price of hedges and other derivatives for the first nine months of 2006 was $46.37 compared to $27.01 for the first nine months of 2005. The remainder of the increase was due to 69,402 more Bbls of oil being subject to hedge arrangements during the first nine months of 2006.

Hedge ineffectiveness and actual hedge losses increased during the period of rising oil prices as experienced from 2003 to 2005 when the average NYMEX price per barrel of crude oil went from $31.07 to $56.56. Hedge ineffectiveness and hedge losses typically decrease during periods of flat or declining oil prices. Because commodity prices can fluctuate significantly, past performance of our hedges is not necessarily indicative of their future performance.

Prices. 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 for natural gas sold decreased slightly 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. The small decrease in overall production sales volumes was less than the natural decline of the underlying properties. The additional production to partially offset the natural decline of the underlying properties during the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 is primarily attributable to lower production caused by an ice storm in Kansas during the first quarter of 2005 and the results of MV Partners' development program in the first nine months of 2006.

Direct operating expenses. Direct operating expenses increased from $12.8 million for the nine months ended September 30, 2005 to $14.7 million for the nine months ended September 30, 2006. This increase was primarily a result of an increase in production and property tax, casing repair to several wells, repair and cleanout of a salt water disposal system well and continuing restoration of wells from inactive status to producing status.

Lease maintenance expense. The increase in lease maintenance expense was primarily due to the timing of scheduled projects in the first nine months of 2006.

Production and property taxes. Production and property taxes increased as a result of the increases in the price of crude oil and in revenues from oil, natural gas and natural gas liquid sales, on which these taxes are based.

Excess of revenues over direct operating expenses for the underlying properties was $18.8 million for the year ended December 31, 2005, compared to $15.5 million for the year ended December 31, 2004. The increase was primarily a result of an increase in the average price received for the oil and natural gas sold. This was partially offset by a decrease in production and an increase in direct operating expenses.

Revenues. Revenues from oil, natural gas and natural gas liquid sales increased $13.0 million between the periods. This increase in revenues was primarily the result of an increase in the average price received for crude oil sold from $39.37 per Bbl for the year ended December 31, 2004 to $54.21 per Bbl for the year ended December 31, 2005. The increase in revenues was also the result of an increase in the average price received for natural gas sold from $5.51 per Mcf for the year ended December 31, 2004 to $6.83 per Mcf for the year ended December 31, 2005.

Hedge and other derivative activity. Hedge and other derivative activity expense increased from $14.4 million for the year ended December 31, 2004 to $22.3 million for the year ended December 31, 2005. This increase was due primarily to the higher average NYMEX settle price for the year ended December 31, 2005 of $56.57 compared to $41.38 for the year ended December 31, 2004. The weighted average hedge price for 2005 was $28.60 compared to $24.02 for 2004. A small increase was due to ineffectiveness of hedges currently in place being recorded to the expense account. In the year ended December 31, 2005, a $0.8 million expense for ineffectiveness was recorded compared to no ineffective portion for the year ended December 31, 2004.

Prices. The average price received for crude oil and natural gas sold increased primarily as a result of an increase in the oil price and natural gas price indices on which the sales prices for a majority of the production were based.

Volumes. The decrease in oil, natural gas and natural gas liquid sales volumes was attributable to the natural decline of proved producing volumes along with a 2% production loss due to widespread ice storms in January and February of 2005. These declines were in part offset by the results of MV Partners' development program in 2005.

Direct operating expenses. Direct operating expenses increased from $15.3 million for the year ended December 31, 2004 to $17.2 million for the year ended December 31, 2005. This increase was primarily a result of increased costs of primary vendors who rely on large uses of hydrocarbon products such as (1) pumpers (gasoline), (2) utilities (cost of fuel), (3) treating chemicals (hydrocarbon base) and (4) pulling units (fuel surcharge). This increase was also supplemented by wage increases associated with the increased demand for oilfield employees and increases in the price of steel for tubular and other metal products.

Lease maintenance expense. Reactivating shut-in wells accounted for the largest part of the increase in lease maintenance expenses during 2005. The same factors described above in direct operating expenses concerning increased costs of primary vendors also contributed to the increase in lease maintenance expense.

Production and property taxes. Production and property taxes increased $0.5 million as a result of the increase in revenues from oil, natural gas and natural gas liquid sales and increased equipment value on which these taxes are based.

Excess of revenues over direct operating expenses for the underlying properties was $15.5 million for the year ended December 31, 2004, compared to $13.2 million for the year ended December 31, 2003. The increase was primarily a result of an increase in the average price received for the oil and natural gas sold. This was partially offset by a decrease in production and an increase in direct operating expenses.

Revenues. Revenues from oil, natural gas and natural gas liquid sales increased $9.8 million between these periods. This increase in revenues was primarily the result of an increase in the average price received for crude oil sold from $28.89 per Bbl for the year ended December 31, 2003 to $39.37 per Bbl for the year ended December 31, 2004. The increase in revenues was also the result of an

increase in the average price received for natural gas sold from $4.84 per Mcf for the year ended December 31, 2003 to $5.51 per Mcf for the year ended December 31, 2004.

Hedge and other derivative activity. Hedge and other derivative activity expense increased from $7.4 million for the year ended December 31, 2003 to $14.4 million for the year ended December 31, 2004. This increase was due primarily to the higher average NYMEX settle price for the year ended December 31, 2004 of $41.38 compared to $31.07 for the year ended December 31, 2003. The weighted average hedge price for 2004 was $24.02 compared to $22.14 for 2003.

Volumes. The decrease in oil, natural gas and natural gas liquid sales volumes was primarily attributable to the natural decline of proved producing volumes. This decline was in part offset by the results of MV Partners' development program in 2004.

Direct operating expenses. Direct operating expenses increased from $14.9 million for the year ended December 31, 2003 to $15.3 million for the year ended December 31, 2004. This increase of 2.7% was primarily a result of general inflation in MV Partners' primary vendor costs.

Production and property taxes. Production and property taxes increased $0.1 million as a result of the increase in revenues from the sale of oil, natural gas and natural gas liquids on which these taxes are based.

MV Partners acquired the underlying properties in two transactions, the first of which was in 1998 and the second of which was in 1999. MV Partners' primary sources of capital and liquidity have been proceeds from sales of limited partner interests prior to its conversion to a limited liability company, borrowings under its bank credit facility and cash flow from operations. To date, its primary uses of capital have been to service its debt requirements, for development of working interests in its oil and natural gas properties located in Kansas and eastern Colorado and for distributions. It continually monitors its capital resources available to meet its future financial obligations and planned capital expenditures. For more information regarding the liquidity and capital resources of MV Partners, please see "Management's Discussion and Analysis of Financial Condition and Results of Operations of MV Partners—Liquidity and Capital Resources."

The revenues derived from the underlying properties depend substantially on prevailing crude oil and, to a lesser extent, natural gas and natural gas liquid prices. As a result, commodity prices also affect the amount of cash flow available for distribution to the trust unitholders. Lower prices may also reduce the amount of oil, natural gas and natural gas liquids that MV Partners can economically produce. MV Partners sells the oil, natural gas and natural gas liquid production from the underlying properties under floating market price contracts each month. MV Partners has entered into the hedge and other derivative contracts to reduce the exposure of the revenues from oil production from the underlying properties from 2006 through 2010 to fluctuations in crude oil prices and to achieve more predictable cash flow. However, these contracts limit the amount of cash available for distribution if prices increase. The hedge and other derivative contracts consist of fixed price swap contracts and costless collar arrangements that have been placed with major trading counterparties who MV Partners believes represent minimal credit risks. MV Partners cannot provide assurance, however, that these trading counterparties will not become credit risks in the future.

The crude oil swap contracts and costless collar arrangements will settle based on the average of the settlement price for each commodity business day in the contract month. In a swap transaction, the counterparty is required to make a payment to MV Partners for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. MV Partners is required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the settlement price is above the fixed price. In a collar arrangement, the counterparty is required to make a payment to MV Partners for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. MV Partners is required to make a payment to the counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price. Neither party is required to make a payment if the settlement price falls between the fixed floor and ceiling prices. From June 30, 2006 through December 31, 2010, MV Partners' crude oil price risk management positions in swap contracts and collar arrangements are as follows:

	Fixed Price Swaps			Collars
					Weighted Average Price (Per Bbl)
Month	Volumes (Bbls)	Weighted Average Price (Per Bbl)		Volumes (Bbls)	Weighted Average Price (Per Bbl)
Month	Volumes (Bbls)	Weighted Average Price (Per Bbl)		Volumes (Bbls)	Floor		Ceiling
July 2006	70,664	$	63.02	—	$	—	$	—
August 2006	70,349		63.02	—		—		—
September 2006	70,037		63.01	—		—		—
October 2006	69,729		63.01	—		—		—
November 2006	69,422		63.00	—		—		—
December 2006	69,120		63.00	—		—		—
January 2007	16,000		58.31	10,000		61.00		68.00
February 2007	61,000		63.33	10,000		61.00		68.00
March 2007	61,000		63.21	10,000		61.00		68.00
April 2007	61,000		63.08	10,000		61.00		68.00
May 2007	61,000		62.92	10,000		61.00		68.00
June 2007	61,000		62.76	10,000		61.00		68.00
July 2007	61,000		62.61	10,000		61.00		68.00
August 2007	61,000		62.47	10,000		61.00		68.00
September 2007	61,000		62.33	10,000		61.00		68.00
October 2007	61,000		62.18	10,000		61.00		68.00
November 2007	61,000		62.04	10,000		61.00		68.00
December 2007	61,000		61.89	10,000		61.00		68.00
January 2008	106,167		60.42	—		—		—
February 2008	61,167		58.53	—		—		—
March 2008	61,167		58.53	—		—		—
April 2008	61,167		58.53	—		—		—
May 2008	61,167		58.53	—		—		—
June 2008	61,167		58.53	—		—		—
July 2008	61,167		58.53	—		—		—
August 2008	61,167		58.53	—		—		—
September 2008	61,167		58.53	—		—		—
October 2008	61,167		58.53	—		—		—
November 2008	61,167		58.53	—		—		—
December 2008	61,167		58.53	—		—		—
January 2009	56,500		66.24	—		—		—
February 2009	56,500		66.24	—		—		—
March 2009	56,500		66.24	—		—		—
April 2009	56,500		66.24	—		—		—

May 2009	56,500	$	66.24	—	$	—	$	—
June 2009	56,500		66.24	—		—		—
July 2009	56,500		66.24	—		—		—
August 2009	56,500		66.24	—		—		—
September 2009	56,500		66.24	—		—		—
October 2009	56,500		66.24	—		—		—
November 2009	56,500		66.24	—		—		—
December 2009	56,500		66.24	—		—		—
January 2010	53,150		65.03	—		—		—
February 2010	53,150		65.03	—		—		—
March 2010	53,150		65.03	—		—		—
April 2010	53,150		65.03	—		—		—
May 2010	53,150		65.03	—		—		—
June 2010	53,150		65.03	—		—		—
July 2010	53,150		65.03	—		—		—
August 2010	53,150		65.03	—		—		—
September 2010	53,150		65.03	—		—		—
October 2010	53,150		65.03	—		—		—
November 2010	53,150		65.03	—		—		—
December 2010	53,150		65.03	—		—		—

MV Partners has agreed to convey to the trust 80% of all proceeds that it receives upon settlement of the hedge contracts. There are certain risks associated with this conveyance in the event that MV Partners becomes involved as a debtor in bankruptcy proceedings. See "Risk Factors—If the financial position of MV Partners degrades in the future, MV Partners may not be able to satisfy its obligations to the trust." In addition, the aggregate amounts paid by MV Partners on settlement of the hedge contracts will be deducted from the gross proceeds available for payment to the trust under the net profits interest. See "Computation of Net Proceeds—Net Profits Interest."

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 June 30, 2006. Undeveloped acreage is not significant.

The following is a summary of the producing wells on the underlying properties as of June 30, 2006:

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 nine months ended September 30, 2006, MV Partners drilled, completed and commenced production with respect to three wells on the underlying properties. MV Partners continued its drilling program in the El Dorado Area in October 2006 with the commencement of drilling of seven additional wells. As of November 30, 2006, three of these seven wells had been completed and were producing, one well was in the process of being completed and completion of the remaining three wells is scheduled for the first half of December 2006. MV Partners expects to commence operations on one additional drilling well in the El Dorado Area near the end of 2006. MV Partners also drilled and set casing on an additional Kansas well during November 2006 and has scheduled completion operations to commence in December 2006. MV Partners has also entered into drilling contracts for two additional Bemis Field wells scheduled to commence during December 2006.

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.

		Year Ended December 31,
		2003		2004		2005
Sales prices:
	Oil (per Bbl)	$	28.89	$	39.37	$	54.21
	Natural gas (per Mcf)	$	4.84	$	5.51	$	6.83
Lease operating expense (per Boe)		$	8.33	$	9.09	$	10.51
Lease maintenance (per Boe)		$	1.09	$	1.27	$	1.78
Lease overhead (per Boe)		$	1.68	$	1.76	$	1.92
Production and property taxes (per Boe)		$	1.08	$	1.21	$	1.74

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 properties comprising 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.

The properties comprising 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.

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 20 infill developmental wells in the Arbuckle, Lansing-Kansas City and Simpson intervals and 16 infill developmental wells in the Whitecloud interval in the El Dorado area during the next five years. Vess Oil also plans to maintain its 11 well annual recompletion and workover program over the next five years. Vess Oil recently received approval from the Kansas Corporation Commission for water injection into the Whitecloud formation and has commenced a waterflood program to enhance production from this reservoir. Vess Oil has completed two active injection wells and plans to convert additional wells as the infill developmental drilling program proceeds. Vess Oil also plans to extend the Admire production facilities in the Oil Hill area, which will enable reactivation of several wells and several recompletion opportunities.

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. Vess Oil plans to drill two wells in the Valley Center Field and equip this area with high volume lift equipment.

Each of Vess Oil and Murfin Drilling operate leases on behalf of MV Partners included in the properties comprising 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 recently conducted a 3-D seismic survey over a large portion of the field to further define the boundaries of the Arbuckle structure in the field and to evaluate undrilled infill locations. This data has been processed and over 14 potential infill drilling locations have been identified. Infill drilling is scheduled to start during the fourth quarter of this year

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.

Murfin Drilling operates the leases held by MV Partners in the Trapp Field. Over the next three years, Murfin Drilling plans to restimulate 12 producing wells and drill one development well in the field and recomplete three wells in other nearby zones.

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 Hansen and Ray Fields. Through the remainder of 2006, Murfin Drilling plans to clean out and acidize six injectors to improve waterflood efficiency within these fields. During the next three years, Murfin Drilling plans to reactivate one producer well and drill one development well.

Since acquiring the underlying properties in 1998 and 1999, MV Partners has implemented a development program on the properties comprising the underlying properties to further develop proved undeveloped reserves and 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 next five years with respect to the underlying properties categorized as proved undeveloped reserves consists of drilling 66 development wells, 51 recompletion and workover projects, 16 polymer stimulations and 1 waterflood project. 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 4 well reactivation projects, 10 injection well workover projects, 1 recompletion project and 28 well workover projects.

Recently, MV Partners undertook a 3-D seismic survey covering several leases constituting a part of the underlying properties. These leases have over 30 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 define smaller structural features along the edges of the main formation reservoir. Using this data, MV Partners has scheduled the drilling of 14 proved undeveloped locations over the next five years. In the future, MV Partners plans to expand its 3-D seismic program into other fields constituting a part of the underlying properties.

MV Partners is also utilizing modern, commercially available technology in various projects, including its work with the Petroleum Technology Transfer Council to implement better applications of gelled polymers in certain reservoirs to increase oil production while reducing associated water production. These treatments are designed to seal the high-permeability channels connecting the water-bearing portions of the reservoir directly to the wellbore. These seals are created by treating the well with a stable polymer gel that shuts-off fluid movement in the channels, which allows bypassed areas of the reservoir to be swept by water and which may result in additional oil being brought to the wellbore. MV Partners has also dedicated significant resources to the study of injecting carbon dioxide into certain reservoirs in Kansas to recover additional otherwise lost oil reserves. This project was partially funded by the Department of Energy in conjunction with the Tertiary Oil Recovery Project at the University of Kansas. MV Partners has achieved successful results using gas gun stimulation in certain workover projects on the properties comprising the underlying properties. Gas gun stimulation is a commercially available technology that involves using a tool that generates a burst of high-pressure gas which creates microfractures in the formation across the perforated reservoir interval.

MV Partners expects total capital expenditures for the underlying properties during the next five years will be approximately $17 million. Of this total, MV Partners contemplated spending approximately $12.8 million to drill approximately 65 development wells in ten project areas and approximately $4.1 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 below) 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 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.

Cawley, Gillespie & Associates, Inc. estimated oil, natural gas and natural gas liquid reserves attributable to the underlying properties as of June 30, 2006. Numerous uncertainties are inherent in

estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the original estimates.

Cawley, Gillespie & Associates, Inc. calculated reserve quantities and revenues attributable to the net profits interest based on projections of reserves and revenues attributable to the underlying properties less reserve quantities of a sufficient value to pay 80% of the future estimated costs, before trust administrative expenses, that are deducted in calculating net proceeds. Proved reserve quantities attributable to the net profits interest are calculated by multiplying the gross reserves for the underlying properties by the net profits interest assigned to the trust in the underlying properties. The net revenues attributable to the trust's reserves are net of the share of applicable production and development expenses, taxes and post-production costs that are used to calculate the net profits interest. The reserves and net revenues attributable to the net profits interest include only the reserves attributable to the underlying properties that are expected to be produced within the term of the net profits interest calculated as described above.

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 as of June 30, 2006, of $70.68 per Bbl of oil, $5.07 per Mcf of natural gas and $56.37 per Bbl of natural gas liquids, as well as costs for estimated future development and production expenditures to produce the proved reserves as of June 30, 2006. The estimated future net revenues from proved reserves also gives effect to the impact of the hedge contracts on the price received in connection with the sale of oil production from the underlying properties. Because oil, natural gas and natural gas liquid prices are influenced by many factors, use of prices as of June 30, 2006, 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 income taxes with respect to the future net cash flows attributable to the underlying properties or the net profits interest because future net revenues are not subject to taxation at the MV Partners or trust level.

Proved Reserves of Underlying Properties and the Net Profits Interest. The following table sets forth, as of June 30, 2006, certain estimated proved reserves, estimated future net revenues and the discounted present value thereof attributable to the underlying properties and the net profits interest, in each case derived from the reserve report. A summary of the reserve report is included as Appendix A to this prospectus.

Information concerning historical changes in net proved reserves attributable to the underlying properties, and the calculation of the standardized measure of discounted future net revenues related thereto, is contained in the unaudited supplemental information contained elsewhere in this prospectus. MV Partners has not filed reserve estimates covering the underlying properties with any other federal authority or agency.

The following table summarizes the changes in estimated proved reserves of the underlying properties for the periods indicated. The data is presented assuming the underlying properties were acquired prior to December 31, 2002.

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 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. For the years ended December 31, 2003, 2004 and 2005, MV Partners plugged and abandoned 8, 12 and 17 wells, respectively, based on its determination that such wells were no longer economic to operate.

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. MV Partners has not identified for sale any of the underlying properties.

Pursuant to the terms of the conveyance creating the net profits interest, MV Partners will have the responsibility to market, or cause to be marketed, the oil, natural gas and natural gas liquid production attributable to the underlying properties. The terms of the conveyance creating the net profits interest do not permit MV Partners to charge any marketing fee when determining the net proceeds upon which the net profits interest will be 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 will be 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.

Kansas is a mature oil producing state with a well-developed transportation infrastructure for crude oil transportation and marketing. According to the Kansas Geological Society, more than 1,700 operators reported oil production of approximately 33.6 million barrels for the State of Kansas during 2005. Kansas is home to three oil refineries located in McPherson, El Dorado and Coffeyville, Kansas. These refineries have combined capacity to refine over 300,000 barrels of oil per day. With oil production in the State of Kansas averaging less than 100,000 barrels of oil per day, Kansas is a net importer of crude oil. As a result, Kansas operators benefit from the competitive marketing conditions for their oil production as a result of the high demand from the refineries located in Kansas.

MV Partners currently sells all of its oil production to third-party crude oil purchasers, including the three refineries identified above, at market prices. A substantial portion of the crude oil produced from the underlying properties is sold to Eaglwing, L.P. and SemCrude, L.P. The members of MV Energy and certain members of MV Partners' other member, VAP-I, including each of Messrs. Vess and Murfin, own minority interests in Eaglwing and SemCrude. Each of these purchasers buys crude oil from MV Partners at market prices, and MV Partners does not have a contract with either purchaser for the sale of crude oil production. MV Partners does not believe that the loss of either of these parties as a purchaser of crude oil production from the underlying properties would have a material impact on the business or operations of MV Partners or the underlying properties because of the competitive marketing conditions in Kansas as described above.

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 contracts 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 that is then reduced for differentials based upon delivery location and oil quality. The average differential for oil production during the month on June 2006 was $3.25 per barrel, though MV Partners expects that differential to increase in the future.

All natural gas produced by MV Partners is marketed and sold to third-party purchasers. The natural gas is sold on 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.

The properties comprising 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 properties comprising the underlying properties are typically subject, in one degree or another, to one or more of the following:

MV Partners believes that the burdens and obligations affecting the properties comprising the underlying properties are conventional in the industry for similar properties. MV Partners also believes that the existing burdens and obligations do not, in the aggregate, materially interfere with the use of the underlying properties and will 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 undertook a thorough title examination of the underlying properties.

MV Partners will record 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 believes that the delivery and recording of the conveyance will constitute fully conveyed and vested property interests in the trust under Kansas law. Although no assurance can be given, 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, but Colorado courts have not directly determined whether a net profits interest is a real or a personal property interest. MV Partners believes that it is possible that the net profits interest may not be treated as a real property interest under the laws of Colorado. MV Partners intends, however, to record the conveyance of the net profits interest in the real property records of Colorado in accordance with local recording acts. 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.

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, 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 cashflow. The trust will be 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.

General. The operations of the properties comprising 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:

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on the operating costs of the properties comprising the underlying properties.

The following is a summary of the existing laws, rules and regulations to which the operations of the properties comprising 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 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 properties comprising 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 properties comprising 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 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.

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, 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.

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 the 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.

The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has not actively considered recent proposed legislation directed at reducing greenhouse gas emissions. However, 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. 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 properties comprising the underlying properties. The operations of the properties comprising 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.

MV Partners believes that it is in substantial compliance with all existing environmental laws and regulations applicable to the current operations of the properties comprising 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 year ended December 31, 2005. Additionally, as of the date of this prospectus, it is not aware of any environmental issues or claims that will require material capital expenditures during 2006. However, there is no assurance that the passage of more stringent laws or regulations in the future will not have an negative impact on the operations of the properties comprising the underlying properties and the cash distributions to the trust unitholders.

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. This summary may not contain all information that is important to you. For more detailed provisions concerning the net profits interest, you should read the conveyance. A copy of the conveyance has been filed as an exhibit to the registration statement. See "Where You Can Find More Information."

The term net profits interest will be conveyed to the trust by MV Partners by means of a conveyance instrument that will be 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 will burden the existing net interests owned by MV Partners in the properties comprising the underlying properties. MV Partners has an average working interest of approximately 94% and an average net revenue interest of approximately 81% in the properties comprising the underlying properties.

The conveyance creating the net profits interest provides that the trust will be entitled to receive an amount of cash for each quarter equal to 80% of the net proceeds (calculated as described below) from the sale of oil, natural gas and natural gas liquid production attributable to the underlying properties.

The amounts paid to the trust for the 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. See "Description of the Trust Units—Distributions and Income Computations."

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.

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) (in either case, 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 $2.1 million in 2005 for all of the properties comprising 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 will be deducted from gross proceeds in the following computation period for purposes of determining the net proceeds for that following computation period.

Gross proceeds and net proceeds are calculated on a cash basis, except that certain costs, primarily ad valorem taxes and expenditures of a material amount, may be determined on an accrual basis.

MV Partners has entered into certain hedge contracts and derivative arrangements related to the oil production from the underlying properties for the years 2006 through 2010. For the years 2006, 2007 and 2008, MV Partners has entered into swap contracts and costless collars at prices ranging from $56 to $68 per barrel of oil that hedge approximately 82% to 86% of expected production from the underlying properties that are classified as proved developed producing in the reserve report. For the years 2009 and 2010, MV Partners has entered into swap contracts at prices ranging from $63 to $71 per barrel of oil that hedge approximately 80% of expected production from the underlying properties that are classified as proved developed producing in the reserve report. MV Partners has assigned to the trust the right to receive 80% of all payments payable to MV Partners from hedge contract counterparties upon monthly settlements of the hedge contracts. From June 30, 2006 through December 31, 2010, MV Partners' crude oil price risk management positions in swap contracts and collar arrangements are as follows:

	Fixed Price Swaps			Collars
					Weighted Average Price (Per Bbl)
Year Ended December 31,	Volumes (Bbls)	Weighted Average Price (Per Bbl)		Volumes (Bbls)	Weighted Average Price (Per Bbl)
Year Ended December 31,	Volumes (Bbls)	Weighted Average Price (Per Bbl)		Volumes (Bbls)	Floor		Ceiling
2006	419,321	$	63.01	—	$	—	$	—
2007	687,000		62.52	120,000		61.00		68.00
2008	779,000		58.79	—		—		—
2009	678,000		66.24	—		—		—
2010	637,800		65.03	—		—		—

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

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 prospectus.

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. MV Partners has not identified for sale any of the underlying properties.

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.

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.

The following information and the information included under "Description of the Trust Units" summarize the material information contained in the trust agreement and the conveyance. For more detailed provisions concerning the trust and the conveyance, you should read the trust agreement and the conveyance. Copies of the trust agreement and the conveyance have been filed as exhibits to the registration statement. See "Where You Can Find More Information."

Immediately prior to the closing of this offering, MV Partners will contribute to the trust the term net profits interest in consideration of receipt of 11,500,000 trust units. The trust's first quarterly distribution will consist 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, this cash payment will include 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. In addition, in connection with the trust's second quarterly distribution expected to be made on or about April 25, 2007, MV Partners will contribute cash in an amount equal to the amount that would have been payable to the trust as of the closing of this offering had the net profits interest been in effect since January 1, 2007. The cash contribution will also include 80% of all amounts paid to MV Partners from hedge contract counterparties for settlements related to the period from January 1, 2007 to the closing of this offering. After the offering made hereby, MV Partners will own its net interests in the underlying properties subject to and burdened by the net profits interest. The trust will be entitled to receive 80% of the net proceeds from the sale of oil, natural gas and natural gas liquid volumes produced from the underlying properties calculated in accordance with the terms of the conveyance. In addition, the trust will be entitled to receive 80% of all amounts payable to MV Partners from hedge contract counterparties upon monthly settlements of the hedge contracts.

The trust was created under Delaware law to acquire and hold the net profits interest for the benefit of the trust unitholders pursuant to an agreement between MV Partners, the trustee and the Delaware trustee. 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 properties comprising the underlying properties. Neither MV Partners nor other operators of the properties comprising the underlying properties have any contractual commitments to the trust to provide additional funding or to conduct further drilling on or to maintain their ownership interest in any of these properties. After the conveyance of the net profits interest, however, MV Partners will retain an interest in each of the underlying properties. For a description of the underlying properties and other information relating to them, see "The Underlying Properties."

The beneficial interest in the trust is divided into 11,500,000 trust units. Each of the trust units represents an equal undivided beneficial interest in the assets of the trust. You will find additional information concerning the trust units in "Description of the Trust Units."

Amendment of the trust agreement requires a vote of holders of a majority of the outstanding trust units. However, no amendment may:

Certain amendments to the trust agreement do not require the vote of the trust unitholders. The trustee may, without approval of the trust unitholders, from time to time supplement or amend the trust agreement in order to cure any ambiguity, to correct or supplement any defective or inconsistent provisions, to grant any benefit to all of the trust unitholders or to change the name of the trust, provided such supplement or amendment is not adverse to the interest of the trust unitholders. The business and affairs of the trust will be managed by the trustee. MV Partners has no ability to manage or influence the operations of the trust.

Upon completion of this offering, the assets of the trust will consist of the net profits interest, the right to receive 80% of any payments under the hedge contracts and any cash and temporary investments being held for the payment of expenses and liabilities and for distribution to the trust unitholders.

The duties of the trustee are specified in the trust agreement and by the laws of the State of Delaware, except as modified by the trust agreement. The trustee's principal duties consist of:

In connection with the formation of the trust, the trustee entered into several agreements with MV Partners that impose obligations upon MV Partners that are enforceable by the trustee on behalf of the trust. For example, when making decisions with respect to the development, operation, abandonment or sale of the underlying properties, MV Partners is obligated under the terms of the conveyance of the net profits interest 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. In addition, the trust has entered into an administrative services agreement with MV Partners pursuant to which MV Partners has agreed to perform specified administrative services on behalf of the trust in a good and workmanlike manner in accordance with the sound and prudent practices of providers of similar services. The trustee has the power and authority under the trust agreement to enforce these agreements on behalf of the trust.

If a trust liability is contingent or uncertain in amount or not yet currently due and payable, the trustee may create a cash reserve to pay for the liability. If the trustee determines that the cash on

hand and the cash to be received are insufficient to cover the trust's liability, the trustee may borrow funds required to pay the liabilities. The trustee may borrow the funds from any person, including itself or its affiliates. The trustee may also mortgage the assets of the trust to secure payment of the indebtedness. The terms of such indebtedness and security interest, if funds were loaned by the entity serving as trustee or Delaware trustee or an affiliate thereof, would be similar to the terms which such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship, and such entity shall be entitled to enforce its rights with respect to any such indebtedness and security interest as if it were not then serving as trustee or Delaware trustee. If the trustee borrows funds, the trust unitholders will not receive distributions until the borrowed funds are repaid.

Each quarter, the trustee will pay trust obligations and expenses and distribute to the trust unitholders the remaining proceeds received from the net profits interest. The cash held by the trustee as a reserve against future liabilities or for distribution at the next distribution date must be invested in:

The trust may not acquire any asset except the net profits interest, cash and temporary cash investments, and it may not engage in any investment activity except investing cash on hand.

The trust may merge or consolidate with or into one or more limited partnerships, general partnerships, corporations, business trusts, limited liability companies, or associations or unincorporated businesses if such transaction is agreed to by the trustee and by the affirmative vote of the holders of a majority of the outstanding trust units and such transaction is permitted under the Delaware Statutory Trust Act and any other applicable law.

MV Partners may request that the trustee sell certain of its net profits interest under any of the following circumstances:

Upon dissolution of the trust, the trustee must sell the net profits interest. No trust unitholder approval is required in this event.

The trustee will distribute the net proceeds from any sale of the net profits interest and other assets to the trust unitholders.

The trustee may require any trust unitholder to dispose of his trust units if an administrative or judicial proceeding seeks to cancel or forfeit any of the property in which the trust holds an interest because of the nationality or any other status of that trust unitholder. If a trust unitholder fails to dispose of his trust units, the trustee has the right to purchase them and to borrow funds to make that purchase.

The trustee is not expected to maintain a website for filings made by the trust with the SEC.

The trustee may agree to modifications of the terms of the conveyance or to settle disputes involving the conveyance. The trustee may not agree to modifications or settle disputes involving the

net profits interest part of the conveyance if these actions would change the character of the net profits interest in such a way that the net profits interest becomes a working interest or that the trust becomes an operating business.

Because the trust does not conduct an active business and the trustee has little power to incur obligations, it is expected that the trust will only incur liabilities for routine administrative expenses, such as the trustee's fees and accounting, engineering, legal, tax advisory and other professional fees.

The trust will be responsible for paying all legal, accounting, tax advisory, engineering and stock exchange fees, printing costs and other administrative and out-of-pocket expenses incurred by or at the direction of the trustee or the Delaware trustee. These trust administrative expenses are anticipated to aggregate approximately $600,000 per year, although such costs could be greater or less depending on future events that cannot be predicted. Included in the $600,000 annual estimate is an annual administrative fee of $150,000 for the trustee and an annual administrative fee of $2,500 for the Delaware trustee. In addition, the trust will pay an annual administrative fee to MV Partners, which fee will total $60,000 in 2006 and will increase by 4% each year beginning in January 2007. See "The Trust—Administrative Services Agreement." The trust will also pay, out of the first cash payment received by the trust, the trustee's and Delaware trustee's legal expenses incurred in forming the trust as well as the Delaware trustee's acceptance fee in the amount of $2,500. These costs will be deducted by the trust before distributions are made to trust unitholders.

The trustee will not make business decisions affecting the assets of the trust except to the extent it enforces its rights under the conveyance agreement related to the net profits interest and the administrative services agreement described above under "—Duties and Powers of the Trustee" that will be executed in connection with this offering. Therefore, substantially all of the trustee's functions under the trust agreement are expected to be ministerial in nature. See "—Duties and Powers of the Trustee," above. The trust agreement, however, provides that the trustee may:

In discharging its duty to trust unitholders, the trustee may act in its discretion and will be liable to the trust unitholders only for its own fraud, gross negligence or acts or omissions constituting bad faith. The trustee will not be liable for any act or omission of its agents or employees unless the trustee acted in bad faith or with gross negligence in their selection and retention. The trustee will be indemnified individually or as the trustee for any liability or cost that it incurs in the administration of the trust, except in cases of fraud, gross negligence or bad faith. The trustee will have a lien on the assets of the trust as security for this indemnification and its compensation earned as trustee. Trust unitholders will not be liable to the trustee for any indemnification. See "Description of the Trust Units—Liability of Trust Unitholders." The trustee must ensure that all contractual liabilities of the trust are limited to the assets of the trust and the trustee will be liable for its failure to do so.

The trustee may consult with counsel, accountants, tax advisors, geologists, engineers and other parties the trustee believes to be qualified as experts on the matters for which advice is sought. The trustee will be protected for any action it takes in good faith reliance upon the opinion of the expert.

Except as expressly set forth in the trust agreement, neither the trustee, the Delaware trustee nor the other indemnified parties have any duties or liabilities, including fiduciary duties, to the trust or any trust unitholder. The provisions of the trust agreement, to the extent they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties of these persons otherwise existing at law or in equity, are agreed by the trust unitholders to replace such other duties and liabilities of these persons.

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 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.

Any dispute, controversy or claim that may arise between MV Partners and the trustee relating to the trust will be submitted to binding arbitration before a tribunal of three arbitrators.

The trustee's and the Delaware trustee's compensation will be paid out of the trust's assets. See "—Fees and Expenses."

The principal offices of the trustee are located at 221 West Sixth Street, 1st Floor, Austin, Texas 78701, and its telephone number is (800) 852-1422.

The Delaware trustee and the trustee may resign at any time or be removed with or without cause at any time by a vote of not less than a majority of the outstanding trust units. Any successor must be a bank or trust company meeting certain requirements including having combined capital, surplus and undivided profits of at least $20,000,000, in the case of the Delaware trustee, and $100,000,000, in the case of the trustee.

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 will be in book-entry form only and will not be represented by certificates. The trust will have 11,500,000 trust units outstanding upon completion of this offering.

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) that quarter, over the trust's liabilities for that quarter. Available funds will be reduced by any cash the trustee decides to hold as a reserve against future liabilities. It is expected that quarterly cash distributions during the term of the trust, other than the first quarterly cash distribution, 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). The first distribution to trust unitholders purchasing trust units in this offering will be made on or about February 23, 2007 to trust unitholders owning trust units on February 15, 2007.

Unless otherwise advised by counsel or 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. Trust unitholders will recognize income and expenses for tax purposes in the quarter the trust receives or pays those amounts, rather than in the quarter the trust distributes them. Minor variances may occur. For example, the trustee could establish a reserve in one quarter that would not result in a tax deduction until a later quarter. The trustee could also make a payment in one quarter that would be amortized for tax purposes over several quarters. See "Federal Income Tax Consequences."

The trustee will file all required trust federal and state income tax and information returns. The trustee will prepare and mail to trust unitholders annual reports that trust unitholders need to correctly report their share of the income and deductions of the trust. The trustee will also cause to be prepared and filed reports required to be filed under the Securities Exchange Act of 1934, as amended, and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading, and will also cause the trust to comply with all of the provisions of the Sarbanes-Oxley Act, including but not limited to, establishing, evaluating and maintaining a system of internal controls over financial reporting in compliance with the requirements of Section 404 thereof.

Each trust unitholder and his representatives may examine, for any proper purpose, during reasonable business hours, the records of the trust and the trustee.

Under the Delaware Statutory Trust Act, trust unitholders will be 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.

The trustee or trust unitholders owning at least 10% of the outstanding trust units may call meetings of trust unitholders. The trust will be 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 will be 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:

In addition, certain amendments to the trust agreement may be made by the trustee without approval of the trust unitholders. See "Description of the Trust Agreement—Creation and Organization of the Trust; Amendments." 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.

Trust unitholders have more limited voting rights than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for annual or other periodic re-election of the trustee.

You should also be aware of the following ways in which an investment in trust units is different from an investment in common stock of a corporation.

	Trust Units	Common Stock
Voting	The trust agreement provides voting rights to trust unitholders to remove and replace the trustee and to approve or disapprove major trust transactions.	Corporate statutes provide voting rights to stockholders to elect directors and to approve or disapprove major corporate transactions.
Income Tax	The trust is not subject to income tax; trust unitholders are subject to income tax on their pro rata share of trust income, gain, loss and deduction.	Corporations are taxed on their income and their stockholders are taxed on dividends.
Distributions	Substantially all trust revenue is required to be distributed to trust unitholders.	Stockholders receive dividends at the discretion of the board of directors.
Business and Assets	The business of the trust is limited to specific assets with a finite economic life.	A corporation conducts an active business for an unlimited term and can reinvest its earnings and raise additional capital to expand.
Fiduciary Duties	The trustee shall not be liable to the trust unitholders for any of its acts or omissions absent its own fraud, gross negligence or bad faith.	Officers and directors have a fiduciary duty of loyalty to stockholders and a duty to use due care in management and administration of a corporation.

Prior to this offering, there has been no public market for the trust units. Sales of substantial amounts of the trust units in the open market, or the perception that those sales could occur, could adversely affect prevailing market prices.

Upon completion of this offering, there will be outstanding 11,500,000 trust units. All of the 7,500,000 trust units sold in this offering, or the 8,625,000 trust units if the underwriters exercise their option to purchase additional trust units in full, will be freely tradable without restriction under the Securities Act. All of the trust units outstanding other than the trust units sold in this offering (a total of 4,000,000 trust units, or 2,875,000 trust units if the underwriters exercise their option to purchase additional shares in full) will be "restricted securities" within the meaning of Rule 144 under the Securities Act and may not be sold other than through registration under the Securities Act or pursuant to an exemption from registration, subject to the restrictions on transfer contained in the lock-up agreements described below and in "Underwriting."

In connection with this offering, MV Partners and its members have agreed, for a period of 180 days after the date of this prospectus, not to offer, sell, contract to sell or otherwise dispose of or transfer any trust units or any securities convertible into or exchangeable for trust units without the prior written consent of Raymond James & Associates, Inc., subject to specified exceptions. See "Underwriting" for a description of these lock-up arrangements. Upon the expiration of these lock-up agreements, 4,000,000 trust units, or 2,875,000 trust units if the underwriters exercise their option to purchase additional trust units in full, will be eligible for sale in the public market under Rule 144 of the Securities Act, subject to volume limitations and other restrictions contained in Rule 144, or through registration under the Securities Act.

In general, under Rule 144 as currently in effect, beginning 90 days after the date of this prospectus, a person or persons whose trust units are aggregated, who has beneficially owned restricted trust units for at least one year, including the holding period of any prior owner, would be entitled to sell within any three-month period a number of shares that does not exceed the greater of:

Sales under Rule 144 also are subject to manner of sale provisions and notice requirements and to the availability of current public information about MV Oil Trust.

Under Rule 144(k), a person who is not deemed to have been an affiliate of MV Oil Trust at any time during the three months preceding a sale and who has beneficially owned the trust units proposed to be sold for at least two years, including the holding period of any prior owner (other than an affiliate of MV Oil Trust) is entitled to sell those shares without complying with the manner of sale, public information, volume limitation or notice provisions of Rule 144.

The trust intends to enter into a registration rights agreement with MV Partners in connection with MV Partners' contribution to the trust of the net profits interest. In the registration rights agreement, the trust will agree, for the benefit of MV Partners and any transferee of its trust units (each, a "holder"), to register the trust units it holds. Specifically, the trust will agree:

The holders will have the right to require the trust to file up to three registration statements and will have piggyback registration rights in certain circumstances.

In connection with the preparation and filing of any registration statement, MV Partners will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the trust, which will be borne by the trustee, and any underwriting discounts and commissions, which will be borne by the seller of the trust units.

The following is a discussion of the material U.S. federal income tax considerations that may be relevant to prospective trust unitholders and, unless otherwise noted in the following discussion, expresses the opinion of Vinson & Elkins L.L.P., insofar as it relates to matters of law and legal conclusions. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the "Code"), existing (and to the extent noted proposed) Treasury regulations thereunder, and current administrative rulings and court decisions, all of which are subject to change or different interpretation at any time, possibly with retroactive effect. Subsequent changes in such authorities may cause the U.S. federal income tax consequences to vary substantially from the consequences described below. No attempt has been made in the following discussion to comment on all U.S. federal income tax matters affecting the trust or the trust unitholders.

The following discussion is limited to trust unitholders who purchase the trust units upon the initial issuance at the initial issue price (which will equal the first price at which a substantial amount of trust units are sold to the public for cash) and who hold the trust units as "capital assets" (generally, property held for investment). All references to "trust unitholders" (including U.S. trust unitholders and non-U.S. trust unitholders) are to beneficial owners of the trust units. This summary does not address the effect of the U.S. federal estate or gift tax laws or the tax considerations arising under the law of any state, local or foreign jurisdiction. Moreover, the discussion has only limited application to trust unitholders subject to specialized tax treatment such as, without limitation:

Prospective investors are urged to consult their own tax advisors as to the particular tax consequences to them of the ownership and disposition of an investment in trust units, including the applicability of any U.S. federal income, federal estate or gift tax, state, local and foreign tax laws, changes in applicable tax laws and any pending or proposed legislation.

As used herein, the term "U.S. trust unitholder" means a beneficial owner of trust units that for U.S. federal income tax purposes is:

The term "non-U.S. trust unitholder" means any beneficial owner of a trust unit that is not a U.S. trust unitholder.

If a partnership (including for this purpose any entity or arrangement treated as a partnership for U.S. federal income tax purposes) is a beneficial owner of trust units, the tax treatment of a partner in the partnership will depend upon the status of the partner and the activities of the partnership. A trust unitholder that is a partnership, and the partners in such partnership, should consult their own tax advisors about the U.S. federal income tax consequences of purchasing, owning, and disposing of trust units.

In the opinion of Vinson & Elkins, L.L.P., for U.S. federal income tax purposes, the trust will be treated as a grantor trust and not as an unincorporated business entity. As a grantor trust, the trust will not be subject to tax at the trust level. Rather, the grantors, who in this case are the trust unitholders, will be considered to own and receive the trust's assets and income and will be directly taxable thereon as though no trust were in existence. The trust will file information returns, reporting to the trust unitholders all items of income, gain, loss, deduction and credit, which must be included in the tax returns of the trust unitholders based on their respective methods of accounting and tax years without regard to the accounting method and tax year of the trust.

No ruling has been or will be requested from the IRS with respect to the U.S. federal income tax treatment of the trust, including a ruling as to the status of the trust as a grantor trust or as a partnership for U.S. federal income tax purposes. Thus, no assurance can be provided that the opinions and statements set forth in this discussion of U.S. federal income tax consequences would be sustained by a court if contested by the IRS.

The remainder of the discussion below is based on Vinson & Elkins L.L.P.'s opinion that the trust will be classified as a grantor trust for federal income tax purposes.

Because the trust will be treated as a trust for U.S. federal income tax purposes, trust unitholders will be treated for such purposes as owning a direct interest in the assets of the trust, and each trust unitholder will be taxed directly on his pro rata share of the income and gain attributable to the assets of the trust and will be entitled to claim his pro rata share of the deductions and expenses attributable to the assets of the trust (subject to certain limitations discussed below). Income, gain, loss, deduction and credits attributable to the assets of the trust will be taken into account by trust unitholders

consistent with their method of accounting and without regard to the taxable year or accounting method employed by the trust.

Following the end of each quarter, the trustee will determine the amount of funds available as of the end of such quarter for distribution to the trust unitholders and will make distributions of available funds, if any, to the unitholders on or about the 25th day of the month following the end of the quarter to the unitholders of record on the last business day of such quarter. In certain circumstances, however, a trust unitholder will not receive the distribution attributable to such income. For example, if the trustee establishes a reserve or borrows money to satisfy liabilities of the trust, income associated with the cash used to establish that reserve or to repay that loan must be reported by the trust unitholder, even though that cash is not distributed to him.

As described above, the trust will allocate items of income, gain, loss, deductions and credits to trust unitholders based on record ownership at the quarterly record dates. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the unitholders affected by the issue and result in an increase in the administrative expense of the trust in subsequent periods.

Based on representations made by MV Partners regarding the expected economic life of the underlying properties and the expected duration of the net profits interest, the net profits interest should be treated as a "production payment" under Section 636 of the Code or otherwise as a debt instrument for U.S. federal income tax purposes. Thus, each trust unitholder should be treated as making a loan on the underlying properties to MV Partners in an aggregate amount generally equal to the purchase price of the trust units reduced by the portion of the purchase price allocated to the trust's right to receive payments under the hedge contracts, and proceeds payable to the trust from the sale of production from the burdened properties should be treated as payments of principal and interest on a debt instrument issued by MV Partners.

We will treat the net profits interest as indebtedness subject to the Treasury Regulations applicable to contingent payment debt instruments (the "CPDI regulations"), and by purchasing trust units, each trust unitholder will agree to be bound by our application of the CPDI regulations, including our determination of the rate at which interest will be deemed to accrue on the net profits interest (treated as a debt instrument for U.S. federal income tax purposes). The remainder of this discussion assumes that the net profits interest will be treated in accordance with that agreement and our determinations. No assurance can be given that the IRS will not assert that the net profits interest should be treated differently. 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 interest income at a rate different than the "comparable yield" described below.

Under the CPDI regulations, U.S. trust unitholders generally will be required to accrue income on the net profits interest in the amounts described below, regardless of whether the U.S. trust unitholder uses the cash or accrual method of tax accounting.

The CPDI regulations provide that a U.S. trust unitholder must accrue an amount of ordinary interest income for U.S. federal income tax purposes, for each accrual period prior to and including the maturity date of the debt instrument that equals:

The "issue price" of the debt instrument held by the trust is the first price at which a substantial amount of the trust units is sold to the public (other than the amount of such purchase price allocated to the trust's right to receive payments under the hedge contracts), excluding sales to bond houses, brokers or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers. The "adjusted issue price" of such a debt instrument is its issue price increased by any interest income previously accrued, determined without regard to any adjustments to interest accruals described below, and decreased by the projected amount of any payments scheduled to be made with respect to the debt instrument at an earlier time. The term "comparable yield" means the annual yield we would be expected to pay, as of the initial issue date, on a fixed rate debt security with no contingent payments but with terms and conditions otherwise comparable to those of the debt instrument represented by ownership of trust units.

We have determined that the comparable yield for the debt instrument held by the trust is an annual rate of %, compounded semi-annually. The CPDI regulations require that we provide to trust unitholders, solely for determining the amount of interest accruals for U.S. federal income tax purposes, a schedule of the projected amounts of payments, which we refer to as projected payments, on the debt instrument held by the trust. These payments set forth on the schedule must produce a total return on such debt instrument equal to its comparable yield. Amounts treated as interest under the CPDI regulations are treated as original issue discount for all purposes of the Code.

As required by the CPDI regulations, for U.S. federal income tax purposes, each holder of trust units must use the comparable yield and the schedule of projected payments as described above in determining its interest accruals, and the adjustments thereto described below, in respect of the debt instrument held by the trust. You may obtain the projected payment schedule by submitting a written request for such information to MV Partners at 250 N. Water, Suite 300, Wichita, Kansas 67202, Attention: President.

Our determinations of the comparable yield and the projected payment schedule are not binding on the IRS and it could challenge such determinations. If it did so, and if any such challenge were successful, then the amount and timing of interest income accruals of the trust unitholders would be different from those reported by us or included on previously filed tax returns by the trust unitholders.

The comparable yield and the schedule of projected payments are not determined for any purpose other than for the determination for U.S. federal income tax purposes of a trust unitholder's interest accruals and adjustments thereof in respect of the debt instrument represented by ownership of trust units and do not constitute a projection or representation regarding the actual amounts payable on the trust units.

If, during any taxable year, a U.S. trust unitholder receives actual payments with respect to the debt instrument held by the trust that in the aggregate exceed the total amount of projected payments for that taxable year, the trust unitholder will incur a "net positive adjustment" under the CPDI

regulations equal to the amount of such excess. The U.S. trust unitholder will treat a "net positive adjustment" as additional interest income for such taxable year.

If a U.S. trust unitholder receives in a taxable year actual payments with respect to the debt instrument held by the trust that in the aggregate are less than the amount of projected payments for that taxable year, the U.S. trust unitholder will incur a "net negative adjustment" under the CPDI regulations equal to the amount of such deficit. This adjustment will (a) reduce the U.S. trust unitholder's interest income on the debt instrument held by the trust for that taxable year, and (b) to the extent of any excess after the application of (a) give rise to an ordinary loss to the extent of the trust unitholder's interest income on such debt instrument during prior taxable years, reduced to the extent such interest was offset by prior net negative adjustments. Any negative adjustment in excess of the amount described in (a) and (b) will be carried forward, as a negative adjustment to offset future interest income in respect of the debt instrument held by the trust or to reduce the amount realized on a sale, exchange, conversion or retirement of such debt instrument.

As the effect of the trust's right to receive payments under the hedge contracts is not definitively addressed by presently existing authorities, the net profits interest may not be treated as a debt instrument for federal income tax purposes. 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 qualification of the net profits interest as a production payment, and thus as a debt instrument, under Section 636 of the Code. However, tax counsel believes that the integration of the two interests, if asserted, would be unlikely to be sustained, as any such integration would be contrary to the form of the conveyances to the trust and inconsistent with the applicable authorities.

If the net profits interest is not treated as a debt instrument, a trust unitholder would be allowed to recoup its basis in the net profits interest on a schedule that is in proportion to expected production from the net profits interest, with the effect that a trust unitholder would be entitled to deductions in respect of basis recovery on a schedule that is more favorable compared to the trust unitholder's entitlement to treat a portion of its receipts as return of principal if the net profits interest is treated, in accordance with tax counsel's opinion, as a debt instrument. In that case, however, the deductions so allowed may be itemized deductions, the deductibility of which would be subject to limitations that disallow itemized deductions that are less than 2% of a taxpayer's adjusted gross income, or reduce the amount of itemized deductions that are otherwise allowable by the lesser of (i) 3% of (A) adjusted gross income over (B) $100,000 ($50,000 in the case of a separate return by a married individual) and (ii) 80% of the amount of itemized deductions that are otherwise allowable, or both. Although the matter is not free from doubt, tax counsel believes that, if the issue became relevant as a result of the classification of the net profits interest as other than a debt instrument, deductions in respect of basis recovery should not be itemized deductions, as the deductions should, under Section 62(a)(4) of the Code, be considered deductions that are attributable to property held for the production of royalty income.

The trust is not entitled to claim depletion deductions with respect to the burdened properties.

A portion of the purchase price paid for trust units will be allocated to the right to receive payments under the hedge contracts. A U.S. trust unitholder's basis in that right will be equal to the amount of such allocated purchase price and will be amortized over the life of the right. As discussed immediately above, certain miscellaneous itemized deductions of an individual taxpayer are subject to limitations on deductibility. Amortization deductions attributable to the portion of the purchase price allocated to the right to receive payments under the hedge contracts will generally be subject to such

limitations. A U.S. trust unitholder will be required to recognize ordinary income with respect to payments received by the trust under the hedge contracts.

For U.S. federal income tax purposes, a sale of trust units will be treated as a sale by the U.S. trust unitholder of his interest in the assets of the trust. Generally, a U.S. trust unitholder will recognize gain or loss on a sale or exchange of trust units equal to the difference between the amount realized and the U.S. trust unitholder's adjusted tax basis for the trust units sold. A U.S. trust unitholder's adjusted tax basis in his trust units will be equal to the U.S. trust unitholder's original purchase price for the trust units, increased by any interest income previously accrued by the U.S. trust unitholder (determined without regard to any adjustments to interest accruals for positive or negative adjustments as described above) and decreased by the amount of any projected payments that have been previously scheduled to be made in respect of the trust units (without regard to the actual amount paid). In addition, such basis will be increased by his share of any payments that are made on the hedge contracts, reduced by the distributions of such amounts and reduced by the amortization deductions with respect to the amount paid for the right to receive payments under the hedge contracts.

Gain recognized upon a sale or exchange of a trust unit attributable to the net profits interest (the amount of which is reduced by any unused adjustments as discussed above) will generally be treated as ordinary interest income. Any loss will be ordinary loss to the extent of interest previously included in income (reduced by any negative adjustments thereto), and thereafter, capital loss (which will be long-term if the trust unit is held for more than one year). Net capital loss may offset no more than $3,000 of ordinary income in the case of individuals and may only be used to offset capital gain in the case of corporations.

Gain or loss upon a sale or exchange of a trust unit attributable to the right to receive payments under the hedge contracts will generally be treated as capital gain or loss.

Expenses of the trust will include administrative expenses of the trustee. As discussed above, certain miscellaneous itemized deductions will generally be subject to limitations on deductibility. Under these rules, administrative expenses attributable to the trust units are miscellaneous itemized deductions that generally will have to be aggregated with an individual unitholder's other miscellaneous itemized deductions to determine the excess over 2% of adjusted gross income. It is anticipated that the amount of such administrative expenses will not be significant in relation to the trust's income.

Payments of principal and interest on, and the proceeds of dispositions of, the trust units, may be subject to information reporting and U.S. federal backup withholding tax if the trust unitholder thereof fails to supply an accurate taxpayer identification number or otherwise fails to comply with applicable U.S. information reporting or certification requirements. Any amounts so withheld will be allowed as a credit against the trust unitholder's U.S. federal income tax liability.

The following is a summary of certain material United States federal income tax consequences that will apply to you if you are a non-U.S. trust unitholder. Non-U.S. trust unitholders should consult their own independent tax advisors to determine the U.S. federal, state, local and foreign tax consequences that may be relevant to them.

Interest paid with respect to the net profits interest will be treated as interest, the amount of which is "contingent" on the earnings of MV Partners, and thus will not qualify for the "portfolio interest exemption" under Sections 871 and 881 of the Code. As a result, such interest will be subject to U.S. federal withholding tax at a 30 percent rate unless the non-U.S. trust unitholder is eligible for a lower rate under an applicable income tax treaty or the interest is effectively connected with the non-U.S. trust unitholder's conduct of a trade or business in the United States, and in either case, the non-U.S. trust unitholder provides appropriate certification. A non-U.S. trust unitholder generally can meet the certification requirement by providing an IRS Form W-8BEN (in the case of a claim of treaty benefits) or a W-8 ECI (with respect to the non-U.S. trust unitholder's conduct of a U.S. trade or business).

Amounts paid with respect to the hedge contracts generally are not subject to U.S. federal income tax or withholding tax, but will be subject to U.S. federal income tax to the extent such amounts are deemed to arise from the conduct of a U.S. trade or business by the non-U.S. trust unitholder.

The net profits interest will be treated as "United States real property interests" for U.S. federal income tax purposes. However, as long as the trust units are regularly traded on an established securities market, gain realized by a non-U.S. trust unitholder on a sale of trust units will be subject to federal income tax only if:

A non-U.S. trust unitholder will be subject to U.S. federal income tax on any gain allocable to the non-U.S. trust unitholder upon the sale by the trust of all or any part of the net profits interest, and distributions to the non-U.S. trust unitholder will be subject to withholding of U.S. tax (currently at the rate of 35%) to the extent the distributions are attributable to such gains.

Payments to non-U.S. trust unitholders of interest, and amounts withheld from such payments, if any, generally will be required to be reported to the IRS and to the non-U.S. trust unitholder.

A non-U.S. trust unitholder may be subject to backup withholding tax, currently at a rate of 28%, with respect to payments from the trust and the proceeds from dispositions of trust units, unless such non-U.S. trust unitholder complies with certain certification requirements (usually satisfied by providing a duly completed IRS Form W-8BEN) or otherwise establishes an exemption. Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules will be allowed as a refund or a credit against a non-U.S. unitholder's U.S. federal income tax liability, provided certain required information is provided to the IRS.

Payments of the proceeds of a sale of a trust unit effected by the U.S. office of a U.S. or foreign broker will be subject to information reporting requirements and backup withholding unless the non-U.S. trust unitholder properly certifies under penalties of perjury as to its foreign status and certain other conditions are met or the non-U.S. trust unitholder otherwise establishes an exemption. Information reporting requirements and backup withholding generally will not apply to any payment of

the proceeds of the sale of a trust unit effected outside of the United States by a foreign office of a broker. However, unless such a broker has documentary evidence in its records that the holder is a non-U.S. trust unitholder and certain other conditions are met, or the non-U.S. trust unitholder otherwise establishes an exemption, information reporting will apply to a payment of the proceeds of the sale of a trust unit effected outside the United States by such a broker if it:

Any amount withheld under the backup withholding rules may be credited against the non-U.S. trust unitholder's U.S. federal income tax liability and any excess may be refundable if the proper information is provided to the IRS.

Employee benefit plans and most other organizations exempt from U.S. federal income tax including IRAs and other retirement plans are subject to U.S. federal income tax on unrelated business taxable income. Because the trust's income is not expected to be unrelated business taxable income, such a tax-exempt organization is not expected to be taxed on income generated by ownership of trust units so long as the trust units are not treated as debt-financed property within the meaning of Section 514(b) of the Code.

PROSPECTIVE INVESTORS IN TRUST UNITS ARE STRONGLY ENCOURAGED TO CONSULT THEIR OWN TAX ADVISORS WITH RESPECT TO THE TAX CONSEQUENCES TO THEM OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF THE TRUST UNITS IN LIGHT OF THEIR OWN PARTICULAR CIRCUMSTANCES, INCLUDING THE TAX CONSEQUENCES UNDER STATE, LOCAL, FOREIGN AND OTHER TAX LAWS AND THE POSSIBLE EFFECTS OF CHANGES IN UNITED STATES FEDERAL OR OTHER TAX LAWS.

The following is intended as a brief summary of certain information regarding state income taxes and other state tax matters affecting individuals who are trust unitholders. Unitholders are urged to consult their own legal and tax advisors with respect to these matters.

Prospective investors should consider state and local tax consequences of an investment in the trust units. The trust will own the net profits interest burdening specified oil and natural gas properties located in the states of Kansas and Colorado. Both of these states have income taxes applicable to individuals.

Kansas income tax law generally conforms to the federal income tax laws, meaning that for Kansas income tax purposes, the trust should be treated as a grantor trust, a trust unitholder should be considered to own and receive his or her share of the trust's assets and income, and the net profits interest should be treated as a debt instrument. An individual trust unitholder who is a nonresident of Kansas generally will not be subject to Kansas income tax on his share of the trust's income, except to the extent the trust units are employed by such trust unitholder in a trade, business, profession or occupation carried on in Kansas. In general, an individual trust unitholder will not be deemed to carry on a trade, business, profession or occupation in Kansas solely by reason of the purchase and sale of

trust units for such nonresident's own account as an investor. An individual trust unitholder who is a resident of Kansas will be subject to Kansas income tax on his share of the trust's income. The trust should not be required to withhold Kansas income tax from distributions made to an individual resident or nonresident trust unitholder as long as the trust is taxed as a grantor trust under the Code.

Colorado has an income tax applicable to individuals; however, the treatment of income from the trust units is unclear under Colorado law. An individual trust unitholder who is a nonresident of Colorado may be required to file Colorado income tax returns and/or pay taxes in Colorado on his share of the trust's income. An individual trust unitholder who is a resident of Colorado will be subject to tax on his share of the trust's income attributable to Colorado. It is anticipated that no more than 5.5% of the trust's income will be attributable to Colorado. Moreover, individual trust unitholders may be subject to penalties for failure to comply with such requirements. The trust should not be required to withhold taxes under Colorado law from distributions made to individual trust unitholders.

The trust units may constitute real property or an interest in real property under the inheritance, estate and probate laws of the states listed above.

The Employee Retirement Income Security Act of 1974, as amended, regulates pension, profit-sharing and other employee benefit plans to which it applies. ERISA also contains standards for persons who are fiduciaries of those plans. In addition, the Internal Revenue Code provides similar requirements and standards which are applicable to qualified plans, which include these types of plans, and to individual retirement accounts, whether or not subject to ERISA.

A fiduciary of an employee benefit plan should carefully consider fiduciary standards under ERISA regarding the plan's particular circumstances before authorizing an investment in trust units. A fiduciary should consider:

A fiduciary should also consider whether an investment in trust units might result in direct or indirect nonexempt prohibited transactions under Section 406 of ERISA and Internal Revenue Code Section 4975. In deciding whether an investment involves a prohibited transaction, a fiduciary must determine whether there are plan assets in the transaction. The Department of Labor has published final regulations concerning whether or not an employee benefit plan's assets would be deemed to include an interest in the underlying assets of an entity for purposes of the reporting, disclosure and fiduciary responsibility provisions of ERISA and analogous provisions of the Internal Revenue Code. These regulations provide that the underlying assets of an entity will not be considered "plan assets" if the equity interests in the entity are a publicly offered security. MV Partners expects that at the time of the sale of the trust units in this offering, they will be publicly offered securities. Fiduciaries, however, will need to determine whether the acquisition of trust units is a nonexempt prohibited transaction under the general requirements of ERISA Section 406 and Internal Revenue Code Section 4975.

The prohibited transaction rules are complex, and persons involved in prohibited transactions are subject to penalties. For that reason, potential employee benefit plan investors should consult with their counsel to determine the consequences under ERISA and the Internal Revenue Code of their acquisition and ownership of trust units.

Immediately prior to the closing of the offering made hereby, MV Partners will convey to the trust the net profits interest in exchange for 11,500,000 trust units. Of those trust units, 7,500,000 are being offered hereby and 4,000,000 will be sold to MV Energy and VAP-I upon the completion of this offering, 1,125,000 of which will be subject to purchase by the underwriters from MV Energy and VAP-I in a subsequent resale pursuant to the underwriters' option to purchase additional trust units. These members of MV Partners may from time to time sell such trust units if the underwriters' option to purchase additional trust units is not exercised in full. MV Partners, MV Energy and VAP-I have agreed, however, not to sell any of such trust units for a period of 180 days after the date of this prospectus without the consent of Raymond James & Associates, Inc., acting as representative of the several underwriters. See "Underwriting."

The following table provides information regarding the selling trust unitholders' ownership of the trust units. This table assumes the underwriters' option to purchase additional trust units is not exercised.

	Ownership of trust units before offering				Ownership of trust units after offering
Selling Trust Unitholders	Ownership of trust units before offering			Number of trust units being offered	Ownership of trust units after offering
Selling Trust Unitholders	Number	Percentage		Number of trust units being offered	Number	Percentage
MV Partners	11,500,000	100.0	%	7,500,000	—	—
MV Energy	—	—		—	2,000,000	17.4	%
VAP-I	—	—		—	2,000,000	17.4	%

Immediately following the closing of this offering, MV Partners intends to sell at the initial public offering price the 4,000,000 trust units not sold in this offering to its two members, MV Energy and VAP-I, in exchange for cash in the amount of $8.0 million and promissory notes. Each of MV Energy and VAP-I will own 50% of the retained units.

Prior to this offering, there has been no public market for the trust units. Therefore, if MV Energy or VAP-I disposes of their retained trust units, the effect of such disposal on future market prices, if any, of market sales of such remaining trust units or the availability of trust units for sale cannot be predicted. Nevertheless, sales of substantial amounts of trust units in the public market could adversely affect future market prices.

Subject to the terms and conditions in an underwriting agreement dated , 2007, the underwriters named below, for whom Raymond James & Associates, Inc., is acting as representative, have severally agreed to purchase from MV Partners the number of trust units set forth opposite their names:

The underwriting agreement provides that the obligations of the underwriters to purchase and accept delivery of the trust units offered by this prospectus are subject to approval by their counsel of legal matters and to other conditions set forth in the underwriting agreement. The underwriters are obligated to purchase and accept delivery of all of the trust units offered by this prospectus if any of the units are purchased, other than those covered by the option to purchase additional trust units described below.

The underwriters propose to offer the trust units directly to the public at the public offering price indicated on the cover page of this prospectus and to various dealers at that price less a concession not in excess of $ per unit. The underwriters may allow, and the dealers may re-allow, a concession not in excess of $ per unit to other dealers. If all of the trust units are not sold at the public offering price, the underwriters may change the public offering price and other selling terms. The trust units are offered by the underwriters as stated in this prospectus, subject to receipt and acceptance by them. The underwriters reserve the right to reject an order for the purchase of the trust units in whole or in part.

MV Partners and its members have granted the underwriters an option, exercisable for 30 days after the date of this prospectus, to purchase from time to time up to an aggregate of 1,125,000 additional trust units to cover over-allotments, if any, at the public offering price less the underwriting discounts and commissions set forth on the cover page of this prospectus. If the underwriters exercise this option, each underwriter, subject to certain conditions, will become obligated to purchase its pro rata portion of these additional units based on the underwriters' percentage purchase commitment in this offering as indicated in the table above. The underwriters may exercise the option to purchase additional trust units only to cover over-allotments made in connection with the sale of the trust units offered in this offering.

The following table shows the amount per unit and total underwriting discounts MV Partners, MV Energy and VAP-I will pay to the underwriters (dollars in thousands, except per unit). The amounts are

shown assuming both no exercise and full exercise of the underwriters' option to purchase additional trust units.

MV Partners will pay Raymond James & Associates, Inc. a structuring fee of $ (or $ if the underwriters exercise their option to purchase additional trust units to cover over-allotments) for evaluation, analysis and structuring of the trust.

The expenses of this offering that are payable by MV Partners are estimated to be $ (exclusive of underwriting discounts and commissions). In no event will the maximum amount of compensation to be paid to members of the National Association of Securities Dealers, Inc., or the "NASD," in connection with this offering exceed 10% plus .5% for bona fide due diligence expenses.

MV Partners and its members, severally and not jointly, have agreed to indemnify the underwriters against various liabilities that may arise in connection with this offering, including liabilities under the Securities Act for errors or omissions in this prospectus or the registration statement of which this prospectus is a part. However, neither MV Partners nor its members will indemnify the underwriters if the error or omission was the result of information the underwriters supplied in writing for inclusion in this prospectus or the registration statement. If MV Partners or its members cannot indemnify the underwriters, they have agreed to contribute to payments the underwriters may be required to make in respect of those liabilities. MV Partners' and its members' respective contributions would be in the proportion that the proceeds (after underwriting discounts and commissions) that MV Partners and its members receive from this offering bear to the proceeds (from underwriting discounts and commissions) that the underwriters receive. If MV Partners and its members cannot contribute in this proportion, MV Partners and its members will contribute based on their respective faults and benefits, as set forth in the underwriting agreement.

Subject to specified exceptions, MV Partners and its members have agreed with the underwriters, for a period of 180 days after the date of this prospectus, not to offer, sell, contract to sell or otherwise dispose of or transfer any trust units or any securities convertible into or exchangeable for trust units without the prior written consent of Raymond James & Associates, Inc. These agreements also preclude any hedging collar or other transaction designed or reasonably expected to result in a disposition of trust units or securities convertible into or exercisable or exchangeable for trust units. Raymond James & Associates, Inc. may, in its discretion and at any time without notice, release all or any portion of the securities subject to these agreements. Raymond James & Associates, Inc. does not have any present intent or any understanding to release all or any portion of the securities subject to these agreements.

in which case the restrictions described in the preceding paragraphs will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release, the announcement of the material news or the occurrence of the material event.

Until this offering is completed, rules of the SEC may limit the ability of the underwriters and various selling group members to bid for and purchase the trust units. As an exception to these rules, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of the trust units, including:

Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of the trust units while this offering is in progress. Stabilizing transactions may include making short sales of trust units, which involve the sale by the underwriter of a greater number of trust units than it is required to purchase in this offering and purchasing trust units from MV Partners or its members or in the open market to cover positions created by short sales. Short sales may be "covered" shorts, which are short positions in an amount not greater than the underwriters' option to purchase additional trust units referred to above, or may be "naked" shorts, which are short positions in excess of that amount.

Each underwriter may close out any covered short position either by exercising its option to purchase additional trust units, in whole or in part, or by purchasing trust units in the open market. In making this determination, each underwriter will consider, among other things, the price of trust units available for purchase in the open market compared to the price at which the underwriter may purchase trust units pursuant to the option to purchase additional trust units.

A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the trust units in the open market that could adversely affect investors who purchased in this offering. To the extent that the underwriters create a naked short position, they will purchase trust units in the open market to cover the position.

The underwriters also may impose a penalty bid on selling group members. This means that if the underwriters purchase trust units in the open market in stabilizing transactions or to cover short sales, the underwriters can require the selling group members that sold those trust units as part of this offering to repay the selling concession received by them.

As a result of these activities, the price of the trust units may be higher than the price that otherwise might exist in the open market. If the underwriters commence these activities, they may discontinue them without notice at any time. The underwriters may carry out these transactions on the New York Stock Exchange or otherwise.

The underwriters and their affiliates may provide in the future investment banking, financial advisory or other financial services for MV Partners and its affiliates, for which they may receive

advisory or transaction fees, as applicable, plus out-of-pocket expenses, of the nature and in amounts customary in the industry for these financial services.

The underwriters may confirm sales of the trust units offered by this prospectus to accounts over which they exercise discretionary authority but do not expect those sales to exceed 5% of the total trust units offered by this prospectus.

The trust units have been approved for listing on the New York Stock Exchange under the symbol "MVO." In connection with the listing of the trust units on the New York Stock Exchange, the underwriters will undertake to sell round lots of 100 units or more to a minimum of 400 beneficial owners.

Prior to this offering, there has been no public market for the trust units. Consequently, the initial public offering price for the trust units will be determined by negotiations among MV Partners and the underwriters. The primary factors to be considered in determining the initial public offering price will be:

A prospectus in electronic format may be available on the Internet sites or through other online services maintained by one or more of the underwriters and selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the underwriter or the selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with MV Partners to allocate a specific number of trust units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter's or any selling group member's website and any information contained in any other website maintained by the underwriters or any selling group member is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been approved or endorsed by MV Partners or any underwriters or any selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

Because the NASD is expected to view the trust units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the NASD's Conduct Rules. Investor suitability with respect to the trust units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Dorsey & Whitney (Delaware) LLP, Wilmington, Delaware, as special Delaware counsel to the trust, will give a legal opinion as to the validity of the trust units. Vinson & Elkins L.L.P., Houston, Texas, will give opinions as to certain other matters relating to the offering, including the tax opinion described in the section of this prospectus captioned "Federal Income Tax Consequences." Certain legal matters in connection with the trust units will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

Certain information appearing in this prospectus regarding the June 30, 2006 estimated quantities of reserves of the underlying properties and net profits interest owned by the trust, the future net revenues from those reserves and their present value is based on estimates of the reserves and present values prepared by or derived from estimates prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers.

The financial statements of MV Partners as of December 31, 2004 and 2005, and for each of the three years in the period ended December 31, 2005, included in this prospectus have been audited by Grant Thornton LLP, independent registered public accountants, as indicated in their report with respect thereto, and are included herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said report.

The statements of historical revenues and direct operating expenses of the underlying properties for each of the three years in the period ended December 31, 2005, included in this prospectus have been audited by Grant Thornton LLP, independent registered public accountants, as indicated in their report with respect thereto, and are included herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said report.

The statement of assets and trust corpus of MV Oil Trust as of August 11, 2006, included in this prospectus has been audited by Grant Thornton LLP, independent registered public accountants, as indicated in their report with respect thereto, and included herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said report.

The trust and MV Partners have filed with the SEC in Washington, D.C. a registration statement, including all amendments, under the Securities Act of 1933 relating to the trust units. As permitted by the rules and regulations of the SEC, this prospectus does not contain all of the information contained in the registration statement and the exhibits and schedules to the registration statement. You may read and copy the registration statement at the SEC's public reference room at 100 F Street, N.E., Washington, D.C. 20549. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at the address in the previous sentence. To obtain information on the operation of the public reference rooms you may call the SEC at (800) SEC-0330. You can also read the trust and MV Partners' SEC filings, including the registration statement, over the Internet at the SEC's website at www.sec.gov.

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.

Completion—The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

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

Development Well—A well drilled into a proved 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.

Farm-in or Farm-out Agreement—An agreement under which the owner of a working interest in an oil or natural gas lease typically assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in" while the interest transferred by the assignor is a "farm-out."

Field—An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

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

Net Acres or Net Wells—The sum of the fractional working interests owned in gross acres or wells, as the case may be.

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.

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.

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 Developed Reserves—Has the meaning given to such term in Rule 4-10(a)(3) of Regulation S-X, which defines proved developed reserves as:

Proved Reserves—Has the meaning given to such term in Rule 4-10(a)(2) of Regulation S-X, which defines proved developed reserves as:

Proved Undeveloped Reserves—Has the meaning given to such term in Rule 4-10(a)(4) of Regulation S-X, which defines proved developed reserves as:

PV-10—The present value of estimated future net revenues using a discount rate of 10% per annum.

Recompletion—The completion for production of an existing well bore in another formation from which that well has been previously completed.

Reservoir—A porous and permeable underground formation containing a natural accumulation of producible oil and/or 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 paragraph 30 of Statement of Financial Accounting Standards No. 69, as follows:

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.

We have audited the accompanying statements of historical revenues and direct operating expenses of the Underlying Properties (the "Properties") of MV Partners, LLC (formerly MV Partners, LP) (the "Partnership") for each of the three years in the period ended December 31, 2005. These statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these 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. The Partnership is not required to have, nor were we engaged to perform, an audit of the Partnership's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statements. We believe that our audits provide a reasonable basis for our opinion.

The accompanying statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note B to the statements and are not intended to be a complete presentation of the Partnership's interests in the Properties.

In our opinion, the statements referred to above present fairly, in all material respects, the historical revenues and direct operating expenses, described in Note B, of the Properties for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

Underlying Properties

STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES

Underlying Properties

NOTES TO STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES

For the years ended December 31, 2003, 2004 and 2005
(information for the nine months ended September 30, 2005 and 2006 is unaudited)

The underlying properties consist of working interests owned by MV Partners, LLC (formerly MV Partners, LP) ("MV") located in Colorado, Kansas and Oklahoma (in 2003 and 2004 only with respect to Oklahoma).

The accompanying statements of historical revenues and direct operating expenses were derived from the historical accounting records of MV and reflect the historical revenues and direct operating expenses directly attributable to the underlying properties for the years and periods described herein. Such amounts may not be representative of future operations. The statements do not include depreciation, depletion and amortization, general and administrative expenses, interest expense or other expenses of an indirect nature. The amounts represent MV's net interest in the wells.

Historical financial statements representing financial position, results of operations and cash flows required by generally accepted accounting principles are not presented as such information is not readily available on an individual property basis and not meaningful to the underlying properties. Accordingly, the statements of historical revenues and direct operating expenses are presented in lieu of the financial statements required under Rule 3-05 of Securities and Exchange Commission Regulation S-X.

The accompanying Statements of Historical Revenues and Direct Operating Expenses included herein were prepared on an accrual basis. Revenue from oil, gas and natural gas liquid sales is recognized when sold.

MV has entered into certain swap and collar agreements to mitigate the effects of fluctuations in the prices of crude oil. These agreements involve the exchange of amounts based on a fluctuating oil price for amounts based on a fixed oil price over the life of the agreement, without an exchange of the notional amount upon which the payments are based. MV accounts for the swap agreements as cash flow hedges. The effective portion of the gain or loss on the swap agreement is recorded in earnings as the underlying hedged item affects income. This effective portion, the ineffective portion of the unrealized gain or loss on the derivative instrument and the change in the unrealized gain or loss on the collar agreements are reflected as hedge and other derivative activity in the accompanying Statements of Historical Revenues and Direct Operating Expenses.

The process of preparing financial statements in conformity with generally accepted accounting principles requires the use of estimates and assumptions regarding certain types of revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts.

The accompanying Statements of Historical Revenues and Direct Operating Expenses for the nine months ended September 30, 2005 and 2006 are unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation on the basis described above, except that the results of operations for the nine months ended September 30, 2006 include a charge for $592,708 that represents ad valorem tax expense for the prior year that was not accrued at December 31, 2005. MV's management does not

expect that the correction of this error will be material to the financial statements for the year ended December 31, 2006.

The estimates of proved reserves and related valuations were based on the reports of Cawley, Gillespie & Associates, Inc., independent petroleum and geological engineers, and the contract property management engineering staff of the sole manager of MV, in accordance with the provisions of SFAS No. 69, Disclosures about Oil and Gas Producing Activities. Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" natural gas, natural gas liquids and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.

The oil and gas reserves are attributable solely to properties within the United States. A summary of the changes in quantities of proved oil, gas and natural gas liquid reserves of the underlying properties for the years ended December 31, 2003, 2004 and 2005 are as follows:

	Oil (Bbls)		Gas (Mcf)		NGL (Bbls)
Balance at January 1, 2003	16,472,230		2,552,088		143,123
Revisions of previous estimates	307,789		(910,403	)	(26,364	)
Extensions and discoveries	13,608		—		—
Production	(1,197,847	)	(116,122	)	(2,734	)

Balance at December 31, 2003	15,595,780		1,525,563		114,025
Revisions of previous estimates	1,444,657		(282,855	)	(875	)
Purchase of minerals in place	16,127		—		—
Extensions and discoveries	846		—		—
Sales of minerals in place	(15,448	)	—		—
Production	(1,126,812	)	(103,540	)	(4,674	)

Balance at December 31, 2004	15,915,150		1,139,168		108,476
Revisions of previous estimates(1)	3,053,651		309,242		5,492
Sales of minerals in place	(5,155	)	—		—
Production	(1,057,906	)	(89,117	)	(4,575	)

Balance at December 31, 2005	17,905,740		1,359,293		109,393

Proved developed reserves:
December 31, 2003	14,913,460		1,348,538		114,025

December 31, 2004	15,317,009		1,139,168		108,476

December 31, 2005	15,888,099		1,062,701		109,393

tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating the underlying properties or their performance.

Management believes that, in reviewing the information that follows, the following factors should be taken into account:

Under the standardized measure, future cash inflows were estimated by applying year-end oil and gas prices, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open hedge and other derivative positions. Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs to arrive at net cash flows. Use of a 10% discount rate and year-end prices and costs are required by SFAS No. 69.

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows at December 31:

Future cash flows as shown above were reported without consideration for the effects of hedge and other derivative transactions outstanding at each period end. If the effects of hedge and other

derivative transactions were included in the computation, then future cash flows would have decreased by $9,816,900, $14,175,700 and $7,655,100 in 2003, 2004 and 2005, respectively.

The changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:

Average prices in effect at December 31, 2003, 2004 and 2005 used in determining future net revenues related to the standardized measure calculation are as follows:

	2003			2005
Oil (per Bbl)	$	30.55	$	41.46	$	57.79
Gas (per Mcf)	$	5.00	$	5.18	$	7.89
NGL (per Bbl)	$	21.96	$	34.62	$	43.74

We have audited the accompanying statement of assets and trust corpus of MV Oil Trust (the "Trust") as of August 11, 2006. This financial statement is the responsibility of the MV Partners, LLC's management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit 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 statement of assets and trust corpus is free of material misstatement. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Trust's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of assets and trust corpus, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall statement of assets and trust corpus presentation. We believe that our audit provides a reasonable basis for our opinion.

As described in Note B to the statement of assets and trust corpus, this statement has been prepared on a 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 statement of assets and trust corpus referred to above presents fairly, in all material respects, the financial position of the Trust as of August 11, 2006, on the basis of accounting described in Note B.

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 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 985 producing oil and gas wells.

The net profits interest is passive in nature and the trustee will have 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 have been produced from the underlying properties and sold, 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.

The Trust uses the cash basis of accounting to report Trust receipts of the term net profits interest, receipts under the hedge and other derivative contracts 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 GAAP financial statements) of the underlying properties times 80% (term net pofits interest percentage). In addition, the trust will be entitled to receive 80% of all payments received by MV Partners upon settlement of the hedge and other derivative contracts. 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 which is on a cash basis of accounting.

Amortization of the investment in net profits interest calculated on a unit-of-production basis is charged directly to trust corpus.

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

Investment in the net profits interest is periodically assessed to determine whether its aggregate value has been impaired below its total capitalized cost based on the underlying properties. The Trust will provide a write-down to its investment in the net profits interest to the extent that total capitalized costs, less accumulated depreciation, depletion and amortization, exceed undiscounted future net revenues attributable to the proved oil and gas reserves of the underlying properties.

The financial information as of September 30, 2006 is unaudited. The Trust has had no operations for the period from inception through September 30, 2006.

The preparation of the financial statements requires the Trust to make estimates and assumptions that affect the reported amount of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Tax counsel to the Trust advised the Trust at the time of formation that, under then current tax laws, the net profits interest should be treated as a debt instrument for federal income tax purposes, and the Trust should be required to treat a portion of each payment it receives with respect to the net profits interest as interest income in accordance with the "noncontingent bond method" under the original issue discount rules contained in the Internal Revenue Code of 1986, as amended and the corresponding regulations. The Trust will be treated as a grantor trust for federal income tax purposes. Trust unitholders will be considered to own and receive the trust's assets and income and will be directly taxable thereon as if no trust were in existence.

The Trustee determines for each quarter the amount available for distribution to the Trust unitholders. This distribution is expected to be made 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). Such amounts will be equal to the excess, if any, of the cash received by the Trust during the preceeding quarter, over the liabilities of the Trust paid during such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for future liabilities of the Trust.

The following unaudited pro forma statement of assets and trust corpus and unaudited pro forma statements of distributable income for the Trust have been prepared to illustrate the conveyance of the term net profits interest in the underlying properties to the Trust by MV Partners, LLC. The unaudited pro forma statement of assets and trust corpus presents the beginning statement of assets and trust corpus of the Trust as of September 30, 2006, giving effect to the net profits interest conveyance as if it occurred on September 30, 2006. The unaudited pro forma statements of distributable income for the year ended December 31, 2005 and the nine months ended September 30, 2006, give effect to the net profits interest conveyance as if it occurred on January 1, 2005, reflecting only pro forma adjustments expected to have a continuing impact on the combined results.

These unaudited pro forma financial statements are for informational purposes only. They do not purport to present the results that would have actually occurred had the net profits interest conveyance been completed on the assumed dates or for the periods presented, or which may be realized in the future.

To produce the pro forma financial information, management made certain estimates. The accompanying unaudited pro forma statement of assets and trust corpus assumes a September 30, 2006 issuance of 11,500,000 trust units at $20.00 per unit. The accompanying unaudited pro forma statements of distributable income for the year ended December 31, 2005 and the nine months ended September 30, 2006 have been prepared assuming trust formation and net profits interest conveyance on January 1, 2005.

These estimates are based on the most recently available information. To the extent there are significant changes in these amounts, the assumptions and estimates herein could change significantly. The unaudited pro forma statement of assets and trust corpus and unaudited pro forma statements of distributable income should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations of MV Partners, LLC" and the historical audited statements of the Trust, MV Partners, LLC and the Underlying Properties, including the related notes, included in this prospectus and elsewhere in the registration statement.

MV Oil Trust

Unaudited Pro Forma Statements of Assets and Trust Corpus

September 30, 2006

The accompanying notes are an integral part of the unaudited pro forma financial information.

MV Oil Trust

Unaudited Pro Forma Statements Of Distributable Income

For the year ended December 31, 2005 and nine months ended September 30, 2006

The accompanying notes are an integral part of the unaudited pro forma financial information.

MV Oil Trust (the "Trust") will own a term net profits interest in oil and gas producing properties located in Kansas and Colorado and owned by MV Partners, LLC. ("MV Partners"). The term net profits interest entitles the Trust to receive 80% of the net proceeds attributable to MV Partners' interest from the sale of production from these 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 have been produced from the underlying properties and sold, and the Trust will soon thereafter wind up its affairs and terminate.

The unaudited pro forma financial information assumes the issuance of 11,500,000 trust units at $20.00 per unit.

The Trust was formed on August 3, 2006 under Delaware law to acquire and hold the net profits interest for the benefit of the holders of the trust units. The net profits interest is passive in nature and the trustee will have no management control over and no responsibility relating to the operation of the underlying properties.

These Unaudited Pro Forma Statements were prepared using the accrual basis information from the historical revenue and direct operating expenses of the underlying properties. The Trust uses the cash basis of accounting to report Trust receipts of the term net profits interest and payments of expenses incurred. 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 which is on a cash basis of accounting. An adjustment is made for the lease equipment cost and lease development expenses which will reduce the cash distributions but are not shown as expenses on the accrual basis historical data.

Investment in the net profits interest is recorded initially at the historic cost of MV Partners and periodically assessed to determine whether its aggregate value has been impaired below its total capitalized cost based on the underlying properties. The Trust will provide a write-down to its investment in the net profits interest to the extent that total capitalized costs, less accumulated depreciation, depletion and amortization, exceed undiscounted future net revenues attributable to the proved oil and gas reserves of the underlying properties.

MV Partners believes that the assumptions used provide a reasonable basis for presenting the significant effects directly attributable to this transaction.

This unaudited pro forma financial information should be read in conjunction with the Statement of Historical Revenues and Direct Operating Costs for Underlying Properties and related notes for the periods presented.

The Trust is a Delaware statutory trust and is not required to pay federal or state income taxes. Accordingly, no provision for Federal or state income taxes has been made.

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

	Year ended December 31, 2005			Nine months ended September 30, 2006
Excess of revenues over direct operating expenses of Underlying Properties including hedge and other derivative activity	$	18,796,921		$	20,531,563
Lease equipment and development costs(1)		2,275,711			1,181,776

Excess of revenues over direct operating expenses and lease equipment and development costs		16,521,210			19,349,787
Times net profits interest over the term of the Trust		80	%		80	%

Income from net profits interest and hedge and other derivative activities	$	13,216,968		$	15,479,830

MV Partners is a privately-held limited liability company engaged in the development and production of established oil and natural gas properties in the Mid-Continent region that are primarily located in Kansas. MV Partners was formed in August 2006 as a result of the conversion of MV Partners, LP to a limited liability company. MV Partners, LP was formed in 1998 to acquire oil and natural gas properties and related assets that were located in Kansas and eastern Colorado from a major oil and gas company. These properties constitute the substantial portion of the underlying properties. MV Partners acquired the remainder of the underlying properties in 1999 from a large independent oil and gas company. MV Energy, which was also formed in 1998, serves as the sole manager of MV Partners and was previously the general partner of MV Partners, LP until its conversion into a limited liability company in August 2006. The acquisition of the underlying properties by MV Partners was originally financed by a large venture capital group, which served as a limited partner of MV Partners until September 2005. In September 2005, MV Partners used bank financing to make distributions to MV Energy and VAP-I to repurchase the limited partner interests held by that large venture capital group. MV Energy is owned equally by Vess Acquisition Group, L.L.C. and Murfin, Inc.

MV Partners has also utilized modern, commercially available techniques and technologies to more completely develop the reserves attributable to the underlying properties. MV Partners is utilizing 3-D seismic technology to further refine development well locations based on traditional subsurface mapping. In addition to using 3-D seismic technology, MV Partners is working on other programs to use developing technology such as its work with the Petroleum Technology Transfer Council concerning

the application of gelled polymers in certain reservoirs to increase oil production and reduce water production, its work with the Department of Energy studying the injection of carbon dioxide to recover oil otherwise lost in the production process and gas gun stimulation technology.

The trust units do not represent interests in, or obligations of, MV Partners.

The underlying properties consist of all of the oil and natural gas properties of MV Partners. Therefore, all information set forth in the prospectus related to the reserves and operations of the underlying properties are the same as the information that would be set forth for MV Partners.

increase or decrease each year based on changes in the Overhead Adjustment Index published by the Council of Petroleum Accountants Societies for that year, year-end index of average weekly earnings of crude petroleum and natural gas workers. In addition, MV Partners pays a monthly administrative services fee to MV Energy for certain corporate administrative and accounting services arranged by MV Energy. Most of these services are performed on behalf of MV Energy by Murfin Drilling and, therefore, MV Energy transmits the entire administrative services fee to Murfin Drilling. The fee is currently $5,000 per month and will increase by 4% each year commencing in January 2007. MV Partners, MV Energy, Vess Oil and Murfin Drilling do not separately allocate or accrue compensation expense for the services performed by employees of Vess Oil or Murfin Drilling on behalf of MV Partners or MV Energy, and their compensation from Vess Oil or Murfin Drilling, as the case may be, is not directly related to the services they perform on behalf of MV Partners or MV Energy. Vess Oil and Murfin Drilling are not contractually obligated to provide the corporate administrative and accounting services on behalf of MV Partners or MV Energy other than the operation of the underlying properties, and MV Partners and MV Energy may contract for the provision of the corporate administrative and accounting services from other parties at any time. Furthermore, none of the members of the executive management team are contractually obligated to continue performing services on behalf of MV Partners and neither Vess Oil nor Murfin Drilling are contractually obligated to make their employees available to perform such services.

Set forth in the table below are the names, ages, function performed on behalf of MV Partners and employer of the members of the executive management team of MV Partners:

Name	Age	Function Performed on Behalf of MV Partners	Employer
J. Michael Vess	55	Co-Chief Executive Officer	Vess Oil
David L. Murfin	54	Co-Chief Executive Officer	Murfin Drilling
Richard J. Koll	56	Chief Financial Officer	Vess Oil
William R. Horigan	56	Vice President—Operations	Vess Oil
Brian Gaudreau	51	Vice President—Land	Vess Oil
Jerry Abels	79	Vice President—Land	Murfin Drilling
Robert D. Young	65	Treasurer	Murfin Drilling
Richard W. Green	64	Controller	Murfin Drilling

acquisition of its oil and natural gas reserves. Mr. Vess received a Bachelor of Business Administration degree from Wichita State University in 1972 and subsequently received his CPA certificate. Mr. Vess currently serves on the Board of Directors and Executive Committees for the Kansas Independent Oil and Gas Association ("KIOGA") and is the current Chairman of the KIOGA Committee on Electricity. He is also a member of the Interstate Oil and Gas Compact Commission Outreach Committee.

Richard W. Green is the Controller of Murfin Drilling. After receiving his Masters in Science Accounting in 1971 from Wichita State University, Mr. Green spent eight years in public accounting

with Peterson, Peterson and Goss CPA's. Mr. Green joined Murfin Drilling as Assistant Controller in 1980.

Under the operating agreement of MV Partners and subject to specified limitations, MV Energy is not liable, responsible or accountable in damages or otherwise to MV Partners or its members for, and MV Partners will indemnify and hold harmless MV Energy from any costs, expenses, losses or damages (including attorneys' fees and expenses, court costs, judgments and amounts paid in settlement) incurred by reason of its being the sole manager of MV Partners.

Vess Oil, which is controlled by Mr. Michael Vess, and Murfin Drilling, which is controlled by Mr. Dave Murfin, operate the underlying properties on a contract operator basis for which MV Partners is designated as the operator. Under the terms of the operating arrangement among MV Partners, Vess Oil and Murfin Drilling, all expenses of Vess Oil and Murfin Drilling incurred on behalf of MV Partners are paid by MV Partners at the cost incurred. Below is a summary of the transactions that occurred between MV Partners and the operators:

The members of MV Energy and certain members of MV Partners' other member, VAP-I, including each of Messrs. Vess and Murfin, own minority interests in Eaglwing, L.P. and SemCrude, L.P., two crude oil purchasers that purchase crude oil production from MV Partners.

A summary of sales and trade receivables with each of these crude oil purchasers follows:

MV Partners also has entered into swap agreements with SemCrude. A summary of the MV Partners' outstanding swap agreements with SemCrude are as follows:

MV Partners had no related party contracts as of December 31, 2004. As of December 31, 2005 and September 30, 2006, MV Partners had an outstanding collar transaction with SemCrude covering 120,000 Bbls of oil during 2007 under which MV Partners will receive payments if oil prices fall below $61 per Bbl or make payments if oil prices rise above $68 per barrel. The fair value of the collar was nominal as of December 31, 2005 and a liability of $328,215 as of September 30, 2006.

From October 1, 2005 through June 30, 2006, certain entities controlled by Messrs. Vess and Murfin made available, on behalf of MV Partners, additional collateral worth approximately $25 million for the benefit of the hedge counterparties to the hedge agreements of MV Partners in effect during that period. As payment for providing this collateral to the hedge counterparties, MV Partners paid the entities that made available the additional collateral a collateral fee equal to 0.75% of the total collateral per annum. Mr. Vess received approximately $44,000 of the collateral fee and Mr. Murfin and members of his immediate family received approximately $85,000 of the collateral fee.

Messrs. Vess and Murfin are also members of the Board of Directors of the American State Bank & Trust Company, National Association, a private banking institution located in Kansas. The American State Bank & Trust Company is obligated to provide up to approximately $3.0 million of credit pursuant to MV Partners' current bank credit facility as a result of a direct participation certificate between American State Bank & Trust Company and Bank of America, N.A., as administrative agent under the bank credit facility. As of December 1, 2006, American State Bank &

Trust Company had outstanding borrowings to MV Partners of approximately $2.7 million under the bank credit facility. These borrowings are expected to be repaid in connection with the refinancing of the bank credit facility using the proceeds from this offering and borrowings under MV Partners' new term loan facility as described in "Management's Discussion and Analysis of Financial Condition and Results of Operations of MV Partners—Liquidity and Capital Resources—Financing Activities."

The following table shows selected historical financial information of MV Partners for each of the five years in the period ended December 31, 2005, and for the nine months ended September 30, 2005 and 2006. The selected historical financial information for each of the three years ended December 31, 2005, is derived from the audited financial statements of MV Partners included elsewhere in this prospectus. The selected historical financial information for each of the nine months ended September 30, 2005 and 2006 is derived from the unaudited financial statements of MV Partners included elsewhere in this prospectus. The selected historical financial information for each of the two years ended December 31, 2002 is derived from the audited financial statements of MV Partners which are not included in this prospectus. The information in this table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations of MV Partners" and the financial statements of MV Partners, related notes and other financial information included elsewhere in this prospectus.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS OF MV PARTNERS

You should read the following discussion of the financial condition and results of operations of MV Partners in conjunction with the historical consolidated financial statements and notes included elsewhere in this prospectus.

MV Partners' revenue, cash flow from operations and future growth depend substantially on factors beyond its control, such as economic, political and regulatory developments and competition from producers of alternative sources of energy. Oil and natural gas prices have historically been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect its financial position, its results of operations, the quantities of oil and natural gas that it can economically produce and its ability to access capital.

Like all businesses engaged in the exploration and production of oil and natural gas, MV Partners faces the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. MV Partners attempts to reduce this natural decline by undertaking field development programs and by implementing secondary recovery techniques. MV Partners intends to maintain its focus on costs necessary to produce its reserves. MV Partners' ability to make capital expenditures to maintain production from its existing reserves and to add reserves through development drilling is dependent on its capital resources and can be limited by many factors.

The discussion and analysis of MV Partners' historical financial condition and results of operations is based upon its consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires it to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. MV Partners evaluates its estimates and assumptions on a regular basis. It bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of its financial statements. MV Partners has provided below an expanded discussion of its more significant accounting policies, estimates and judgments. It believes these accounting policies reflect its more significant estimates and assumptions used in the preparation of its financial statements. Please read Note A of the Notes to the Financial Statements of MV Partners for a discussion of additional accounting policies and estimates made by its management.

MV Partners accounts for oil and natural gas properties by the successful efforts method. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.

Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Statement of Financial Accounting Standards (SFAS) No. 19—Financial Accounting and Reporting for Oil and Gas Producing Companies requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, developed and undeveloped, and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves. As more fully described in Note J of the Notes to the Financial Statements, proved reserves are estimated by an independent petroleum engineer, Cawley, Gillespie & Associates, Inc., and are subject to future revisions based on availability of additional information. As described in Note H of the Notes to the Consolidated Financial Statements, MV Partners follows SFAS No. 143—Accounting for Asset Retirement Obligations. Under SFAS No. 143, estimated asset retirement costs are recognized when the asset is placed in service and are amortized over proved reserves using the units of production method. Asset retirement costs are estimated by its engineers using existing regulatory requirements and anticipated future inflation rates.

Geological, geophysical and dry hole costs on oil and natural gas properties relating to unsuccessful wells are charged to expense as incurred.

Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is credited to income. On sale or retirement of an individual well, the proceeds are credited to accumulated depreciation and depletion.

Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. MV Partners assesses impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. As of December 31, 2004 and 2005, and June 30, 2006, the estimated undiscounted future cash flows for its proved oil and natural gas properties exceeded the net capitalized costs, and no impairment was required to be recognized.

Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.

MV Partners' estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Cawley, Gillespie & Associates, Inc. prepares a reserve and economic evaluation of all its properties on a well-by-well basis.

Reserves and their relation to estimated future net cash flows impact MV Partners' depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. MV Partners prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve reports. The accuracy of its reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.

MV Partners' proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas and natural gas liquids eventually recovered.

MV Partners periodically uses derivative financial instruments to achieve a more predictable cash flow from its oil production by reducing its exposure to fluctuations in the price of crude oil. Currently, these transactions are swaps and collar transactions. It accounts for these activities pursuant to SFAS No. 133—Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities.

The accounting for changes in the fair market value of a derivative instrument depends on the intended use of the derivative instrument and the resulting designation, which is established at the inception of a derivative instrument. SFAS No. 133 requires that a company formally document, at the inception of a hedge, the hedging relationship and the entity's risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment.

For derivative instruments designated as cash flow hedges, changes in fair market value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative instrument's fair market value. Any ineffective portion of the derivative instrument's change in fair market value is recognized immediately in earnings.

Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations," requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred. The liability is measured at discounted fair value and is adjusted to its present value in subsequent periods as accretion expense is recorded. Such accretion expense is included in depreciation, depletion and amortization in the accompanying statements of earnings. The corresponding asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset and amortized over the asset's useful life. MV Partners' asset retirement obligations are primarily associated with the plugging of abandoned oil wells. SFAS No. 143 was effective for MV Partners on January 1, 2003.

Set forth in the table below is a summary of MV Partners' financial data for the periods indicated

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

The financial information with respect to the nine months ended September 30, 2006 and 2005 that is discussed below is unaudited. In the opinion of MV Partners' management, this information contains all adjustments, consisting only of adjustments for normally recurring accruals, necessary for a fair presentation of the results for such periods. The results of operations for these interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Revenues from oil and natural gas sales increased $9.5 million between these periods. This consists of an increase of $8.2 million of oil and natural gas revenues and a $1.3 million decrease in hedge and other derivative activities expense. The $8.2 million increase in revenues was primarily the result of an increase in the average price received for the oil sold from $53.25 per Bbl for the nine months ended September 30, 2005 to $64.91 per Bbl for the nine months ended September 30, 2006, partially offset by a 17 MBbl decrease in oil volumes sold. The increase in revenues was also the result of a 12,399 Mcf increase in natural gas volumes sold, partially offset by a small decrease in the average price received for the natural gas sold from $5.86 per Mcf for the nine months ended September 30, 2005 to $5.68 per Mcf for the nine months ended September 30, 2006.

The decrease in hedge and other derivative activity expense of $1.3 million for the nine months ended September 30, 2006 was due to a decrease in realized hedge losses and an increase in ineffectiveness of hedges and other derivatives then in place being recorded to the expense account for the period.

At September 30, 2006, MV Partners recorded a $1.2 million expense for ineffectiveness of hedges and other derivatives compared to a $0.3 million expense at September 30, 2005. The increase in

ineffectiveness during the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 is partially the result of additional hedge and other derivative contracts placed during the last quarter of 2005. At September 30, 2005, MV Partners had open swap agreements covering the next 15 months and no open collar transactions. At September 30, 2006, MV Partners had open swap agreements covering the next 51 month periods and an open collar transaction covering the 12 months of 2007 which increased the volume of hedges and the exposure to hedge ineffectiveness compared to September 30, 2005. The change in value of the open collar transaction resulted in an expense of $0.3 million for the nine months ended September 30, 2006.

Hedge ineffectiveness of the swap agreements is the result of various factors including changes in the average crude oil price and changes in the basis differential between the NYMEX price and the price actually received by MV Partners. An increase in the basis differential, the increase in the price of crude oil and the extended hedge and derivative contracts, all combined to increase the expense associated with the swap agreements for the nine months ended September 30, 2006 by $0.9 million.

Hedge ineffectiveness and actual hedge losses increased during the period of rising oil prices as experienced from 2003 to 2005 when the average NYMEX price per barrel of crude oil went from $31.07 to $56.56. Hedge ineffectiveness and hedge losses typically decrease during periods of flat or declining oil prices. Because commodity prices can fluctuate significantly, past performance of MV Partners' hedges is not necessarily indicative of their future performance.

Lease operating expenses increased from $12.8 million for the nine months ended September 30, 2005 to $14.7 million for the nine months ended September 30, 2006. This increase was primarily a result of an increase in production and property tax expense due to the increased price of oil and gas on which the taxes are based and casing repair to several wells, repair and cleanout of a salt water disposal system well and continuing restoration of wells from inactive status to producing status. In addition, operating costs associated with primary vendors' fuel increases contributed a small portion of the increase.

Depreciation, depletion and amortization decreased from $2.9 million for the nine months ended September 30, 2005 to $2.4 million for the nine months ended September 30, 2006. Depreciation, depletion and amortization are calculated based on units of production. The decline comes from the previously reduced asset base combined with an increase in the total estimated reserves.

General and administrative expenses increased from $0.4 million for the nine months ended September 30, 2005 to $0.5 million for the nine months ended September 30, 2006. This is an increase primarily due to inflation in general costs.

A loss on sales of assets of $0.1 million was recorded for the nine months ended September 30, 2005 compared to a nominal loss recorded for the nine months ended September 30, 2006.

Interest expense increased from $0.8 million for the nine months ended September 30, 2005 to $4.3 million for the nine months ended September 30, 2006. This is primarily a result of a financing that took place on December 21, 2005. During the nine months ended September 30, 2005, MV Partners' outstanding debt balance increased from $25.0 million to $38.1 million, while during the nine months ended September 30, 2006, its outstanding debt balance decreased from $90.0 million to $83.0 million. In addition, the weighted average interest rate MV Partners paid on its debt obligations increased from 4.5% during the nine months ended September 30, 2005 to 6.6% during the nine months ended September 30, 2006.

Revenues from oil and natural gas sales increased $5.1 million between these periods. This consists of an increase of $13.0 million of oil and natural gas revenues and a $7.9 million increase in hedge and other derivative activities expense. The $13.0 million increase in revenues was primarily the result of an increase in the average price received for the oil sold from $39.37 per Bbl for the year ended December 31, 2004 to $54.21 per Bbl for the year ended December 31, 2005. The increase in revenues was also the result of an increase in the average price received for the natural gas sold from $5.51 per Mcf for the year ended December 31, 2004 to $6.83 per Mcf for the year ended December 31, 2005.

The increase in hedge and other derivative activity expense of $7.9 million for the year ended December 31, 2005 was due primarily to the higher average NYMEX settle price for the year ended December 31, 2005 of $56.57 compared to $41.38 for the year ended December 31, 2004. The weighted average hedge price for 2005 was $28.60 compared to $24.02 for 2004. A small increase was due to ineffectiveness of hedges currently in place being recorded to the expense account. In the year ended December 31, 2005, MV Partners recorded a $0.8 million hedge expense for ineffectiveness compared to no ineffective portion for the year ended December 31, 2004.

Lease operating expenses increased from $15.3 million for the year ended December 31, 2004 to $17.2 million for the year ended December 31, 2005. This increase was primarily a result of increased costs of primary vendors who rely on large uses of hydrocarbon products such as (1) pumpers (gasoline), (2) utilities (cost of fuel), (3) treating chemicals (hydrocarbon base) and (4) pulling units (fuel surcharge). This increase was also supplemented by wage increases associated with the increased demand for oilfield employees and increases in the price of steel for tubular and other metal products.

Depreciation, depletion and amortization decreased from $4.3 million for the year ended December 31, 2004 to $3.8 million for the year ended December 31, 2005. Depreciation, depletion and amortization are calculated based on units of production. The decline comes from the previously reduced asset base combined with an increase in the total estimated reserves.

General and administrative expenses increased from $0.4 million for the year ended December 31, 2004 to $0.5 million for the year ended December 31, 2005. This is an increase primarily due to inflation in general costs.

A gain on sale of assets of $0.2 million was recorded for the year ended December 31, 2004 compared to a loss of $0.1 million recorded for the year ended December 31, 2005.

Interest expense increased from $0.7 million for the year ended December 31, 2004 to $1.5 million for the year ended December 31, 2005. This is a result of the financing that took place on December 21, 2005 resulting in increased liability of $90 million for the end of the year 2005, up from $25 million for the entire year 2004 in addition to the rising interest rates.

Revenues from oil and natural gas sales increased $2.8 million between these periods. This consists of an increase of $9.8 million of oil and natural gas revenues and a $7.0 million increase in hedge and other derivative activities expense. The $9.8 million increase in revenues was primarily the result of an increase in the average price received for the oil sold from $28.89 per Bbl for the year ended December 31, 2003 to $39.37 per Bbl for the year ended December 31, 2004. The increase in revenues was also the result of an increase in the average price received for the natural gas sold from $4.84 per Mcf for the year ended December 31, 2003 to $5.51 per Mcf for the year ended December 31, 2004.

The increase in hedge and other derivative activity expense of $7.0 million for the year ended December 31, 2004 was due primarily to the higher average NYMEX settle price for the year ended December 31, 2004 of $41.38 compared to $31.07 for the year ended December 31, 2003. The weighted average hedge price for 2004 was $24.02 compared to $22.14 for 2003.

Lease operating expenses increased from $14.9 million for the year ended December 31, 2003 to $15.3 million for the year ended December 31, 2004. This increase of 2.7% was primarily a result of general inflation in MV Partners' primary vendor costs.

Depreciation, depletion and amortization decreased from $5.0 million for the year ended December 31, 2003 to $4.3 million for the year ended December 31, 2004. Depreciation, depletion and amortization are calculated based on units of production. The decline comes from the previously reduced asset base combined with an increase in the total estimated reserves.

General and administrative expenses remained constant at $0.4 million for the years ended December 31, 2003 and 2004.

A minimal loss on sale of assets was recorded for the year ended December 31, 2003 compared to a gain on sale of assets of $0.2 million recorded for the year ended December 31, 2004.

Interest expense remained constant at $0.7 million for the year ended December 31, 2003 and 2004. The only bank debt during these periods was an interest only note. A slight increase from $677,000 for the year ended December 31, 2003 to $717,000 for the year ended December 31, 2004 was a result of a rising interest rate.

MV Partners' primary sources of capital and liquidity have been proceeds from sales of limited partner interests prior to its conversion to a limited liability company, borrowings under its bank credit facility and cash flow from operations. To date, its primary uses of capital have been to service its debt requirements, for development of working interests in its oil and natural gas properties located in Kansas and eastern Colorado and for distributions. It continually monitors its capital resources available to meet its future financial obligations and planned capital expenditures.

Net cash provided by operating activities was $17.4 million and $12.2 million for the nine months ended September 30, 2006 and 2005, respectively. The increase in net cash provided by operating activities was due substantially to the change in the price of oil and the reduced amount of hedge liability.

Net cash provided by operating activities was $16.6 million during the year ended December 31, 2005, compared to $13.7 million during the year ended December 31, 2004. The increase in net cash provided by operating activities in 2005 was substantially due to increased revenues partially offset by increased expenses, as discussed above in "—Results of Operations."

MV Partners' cash flow from operations is subject to many variables, the most significant of which are oil and natural gas prices. Oil and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond its control. MV Partners' future cash flow from operations will depend on its ability to maintain and increase production through its development program, as well as the prices of oil and natural gas.

MV Partners has entered into certain hedge contracts related to the oil production from the underlying properties for the years 2006 through 2010. For the years 2006, 2007 and 2008, MV Partners has entered into swap contracts and costless collars at prices ranging from $56 to $68 per barrel of oil that hedge approximately 82% to 86% of expected production from the underlying properties that are classified as proved developed producing in the reserve report. For the years 2009 and 2010, MV Partners has entered into swap contracts at prices ranging from $63 to $71 per barrel of oil that hedge approximately 80% of expected production from the underlying properties that are classified as proved developed producing in the reserve report. The hedge contracts will not be pledged to the trust, but any payments made by MV Partners upon settlement of the hedge contracts will be factored into the calculation of the gross proceeds from the underlying properties. Any proceeds received by MV Partners upon settlement of the hedge contracts will separately be factored into the calculation of

payment due to the trust. From June 30, 2006 through December 31, 2010, MV Partners' crude oil price risk management positions in swap contracts and collar arrangements are as follows:

	Fixed Price Swaps			Collars
					Weighted Average Price (Per Bbl)
Year Ended December 31,	Volumes (Bbls)	Weighted Average Price (Per Bbl)		Volumes (Bbls)	Weighted Average Price (Per Bbl)
Year Ended December 31,	Volumes (Bbls)	Weighted Average Price (Per Bbl)		Volumes (Bbls)	Floor		Ceiling
2006	419,321	$	63.01	—	$	—	$	—
2007	687,000		62.52	120,000		61.00		68.00
2008	779,000		58.79	—		—		—
2009	678,000		66.24	—		—		—
2010	637,800		65.03	—		—		—

By removing the price volatility from a significant portion of its oil production, MV Partners has mitigated, but not eliminated, the potential effects of changing commodity prices on its cash flow from operations for those periods. While mitigating negative effects of falling crude oil prices, these derivative contracts also limit the benefits it would receive from increases in crude oil prices. It is MV Partners' policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers.

MV Partners' capital expenditures were $1.2 million and $1.7 million for the nine months ended September 30, 2006 and 2005, respectively. Capital expenditures for each of the nine months ended September 30, 2006 and September 30, 2005 includes the purchase of oil and natural gas properties and the payment of well development costs. MV Partners also had proceeds from the sale of oil and natural gas properties of $0.1 million for the nine months ended September 30, 2005.

MV Partners' capital expenditures were $2.3 million in the year ended December 31, 2005 and $1.7 million in the year ended December 31, 2004. The total for 2005 includes the purchase of oil and natural gas properties and the payment of well development costs. MV Partners also had proceeds from the sale of oil and natural gas properties of $0.1 million and $0.3 million for the years ended December 31, 2005 and 2004, respectively.

MV Partners currently anticipates that its development budget, which predominantly consists of workover drilling, secondary recovery projects and equipment, will be $8.5 million for the remainder of 2006 and 2007. The amount and timing of its capital expenditures is largely discretionary and within its control. MV Partners' routinely monitors and adjusts its capital expenditures in response to changes in oil and natural gas prices, development costs, industry conditions and internally generated cash flow. Future cash flows are subject to a number of variables, including the level of production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

On December 21, 2005, MV Partners entered into a bank credit facility with a group of bank lenders that provides for a revolving line of credit, letters of credit and swing line loans. The total amount that MV Partners can borrow and have outstanding at any one time is limited to the lesser of the total commitment of $200 million or the borrowing base established by the lenders, with $15 million available for outstanding letters of credit and $0.5 million for outstanding swing line loans. As of September 30, 2006, the borrowing base under the bank credit facility was $90.0 million. As of

September 30, 2006, the principal amount outstanding under the bank credit facility was $83.0 million with no letters of credit or swing line loans outstanding.

The bank credit facility allows MV Partners to borrow, repay and reborrow amounts available under the bank credit facility. The amount of the borrowing base is based primarily upon the estimated value of MV Partners oil and natural gas reserves. Under the credit agreement, the initial borrowing base was $95 million, such borrowing base being reduced to $90 million on July 1, 2006 and $85 million on January 1, 2007. The borrowing base under the bank credit facility is subject to re-determination at least semi-annually. The bank credit facility matures on December 19, 2008, and borrowings under the bank credit facility bear interest, payable quarterly, at MV Partners' option, at (1) a rate (as defined and further described in the bank credit facility) per annum equal to a Eurodollar Rate (which is substantially the same as the London Interbank Offered Rate) for one, two, three or six months as offered by the lead bank under the bank credit facility or (2) the higher of the Federal Funds Rate (as defined and further described in the bank credit facility) plus 50 basis points or such bank's Prime Rate. MV Partners' bank credit facility bore interest at 6.6% per annum as of September 30, 2006. MV Partners pays quarterly commitment fees under the bank credit facility on the unused portion of the available borrowing base ranging from 12.5 to 37.5 basis points, dependent upon the percentage of MV Partners' available borrowing base then utilized.

Borrowings under the bank credit facility are secured by a lien on substantially all of MV Partners' assets and properties. The bank credit facility also contains restrictive covenants that may limit MV Partners' ability to, among other things, pay dividends, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens and engage in certain other transactions without the prior consent of the lenders. The bank credit facility also requires MV Partners to maintain certain ratios as defined and further described in the revolving credit facility, including a current ratio of not less than 1.0 to 1.0 and a maximum leverage ratio of no greater than 2.50 to 1.0. The current ratio is defined to include the amount of the unused borrowing base as a current asset and to exclude current maturities of the credit facility as well as any current liability resulting from any mark to market accounting under SFAS 133. In addition, MV Partners was required to enter into swap agreements covering 90% of estimated production for the three years following December 31, 2005 based on proved reserves as of December 31, 2004, with a fixed price per Bbl of a minimum of $55. As of September 30, 2006, MV Partners was in compliance with all such covenants.

In connection with the closing of this offering, MV Partners intends refinance its bank credit facility and terminate that facility using proceeds from this offering and borrowings under a new senior secured term loan facility. The amount that MV Partners can borrow under the term loan facility is limited to $25 million, and MV Partners intends to draw the full amount available under the term loan facility to refinance its bank credit facility. The term loan facility requires MV Partners to repay the outstanding balance on an amortization schedule of $1.25 million per quarter for 20 quarters, beginning March 30, 2007. MV Partners may prepay any or all of its outstanding balance under the term loan facility at any time without penalty, subject to payment of certain costs of the lenders. Borrowings under the term loan facility bear interest, payable quarterly, at MV Partners' option, at (1) a rate (as defined and further described in the term loan facility) per annum equal to a Eurodollar Rate (which is substantially the same as the London Interbank Offered Rate) for one, two, three or six months offered by the lead bank under the term loan facility plus 2.0% or (2) such bank's Prime Rate.

Borrowings under the term loan facility are secured by a lien on substantially all of MV Partners' assets and properties, though such lien is expressly made subject to the net profits interest. MV Energy and VAP-I are guarantors under the term loan facility. The term loan facility also contains restrictive covenants that may limit MV Partners' ability to, among other things, pay dividends, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens and engage in certain other transactions without the prior consent of the lenders. The term loan facility also requires MV Partners to maintain a consolidated fixed charge coverage ratio of not less than 1.25 to

1.0. The consolidated fixed charge coverage ratio is defined to exclude any expense resulting from any mark to market accounting under SFAS 133.

A summary of MV Partners' contractual obligations as of September 30, 2006 is provided in the following table.

As of September 30, 2006, MV Partners had no off-balance sheet arrangements and currently has no intention to establish any off-balance sheet arrangements.

On March 30, 2005, the FASB issued FIN No. 47—Accounting for Conditional Asset Retirement Obligations. This interpretation clarifies that the term "conditional asset retirement obligation" as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 was effective for MV Partners at the end of the fiscal year ended December 31, 2005. MV Partners does not expect the application of FIN No. 47 to have a significant impact on its financial position or results of operations.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. SFAS No. 154 supersedes SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements, and APB Opinion No. 20, Accounting Changes. SFAS No. 154 requires, unless impracticable, retrospective application to prior periods' financial statements of changes in accounting principle. The provisions of SFAS No. 154 also require that a change in depreciation, amortization, or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. SFAS No. 154 is effective for all accounting changes made in fiscal years beginning after December 15, 2005.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin ("SAB") No. 108, "Considering the Effects of Prior Year Misstatements when Quantifying Current Year Misstatements." SAB No. 108 requires analysis of misstatements using both an income statement (rollover) approach and a balance sheet (iron curtain) approach in assessing materiality and provides for a one-time cumulative effect transition adjustment. We have applied the guidance of SAB No. 108 for all periods presented.

In September 2006, the FASB finalized SFAS No. 157, "Fair Value Measurements," which will become effective in 2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements; however, it does not require any new fair value measurements. The provisions of SFAS No. 157 will be applied prospectively to fair value measurements and disclosures in our financial statements beginning in the first quarter of 2008. The adoption of SFAS No. 157 is not expected to have a material impact on our consolidated financial position or results of operations.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about MV Partners' potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how MV Partners views and manages its ongoing market risk exposures. All of its market risk sensitive instruments were entered into for purposes other than speculative trading.

MV Partners' major market risk exposure is in the pricing applicable to its oil and natural gas production. Realized pricing is primarily driven by the spot market prices applicable to its oil production and the prevailing price for natural gas. Pricing for oil production has been volatile and unpredictable for several years, and it expects this volatility to continue in the future. The prices it receives for oil and natural gas production depend on many factors outside of its control.

MV Partners has entered into hedging arrangements with respect to a portion of its projected oil production through various transactions that hedge the future prices received. These transactions are typically price swaps whereby it will receive a fixed price for its production and pay a variable market price to the contract counterparty. These hedging activities are intended to support oil prices at targeted levels and to manage its exposure to oil price fluctuations.

Based on an oil price of $62.91 per Bbl as of September 30, 2006, the fair value of its hedge positions for 2006 was a liability of $11.7 million, which it owed to the counterparty. A 10% increase in the index oil price above the September 30, 2006 price for oil would increase the liability by $17.8 million; conversely, a 10% decrease in the index oil price would decrease the liability by $17.8 million.

MV Partners also entered into a collar agreement. As of September 30, 2006, the fair market value of its collar agreement was a liability of $0.3 million. The hedges and other derivative arrangements for the remainder of 2006 and through December 2010 are summarized in the table presented above under "—Liquidity and Capital Resources—Cash Flow from Operating Activities."

At September 30, 2006, MV Partners had debt outstanding under its bank credit facility of $83.0 million. The weighted average annual interest rate under the bank credit facility for the nine months ended September 30, 2006 was 6.6%. If prevailing market interest rates had been 1% higher as of September 30, 2006, and all other factors affecting MV Partners' debt remained the same interest expense on an annual basis would have been $0.8 million higher.

The following is a summary of the material provisions of the First Amended and Restated Operating Agreement of MV Partners by and between MV Energy and VAP-I, as amended. A copy of the Operating Agreement, as well as the amendment thereto, is included as an exhibit to the registration statement to which this prospectus forms a part.

MV Partners was organized as a Kansas limited liability company on August 1, 2006 as the successor by conversion to MV Partners, LP, and will remain in existence until dissolved in accordance with the Operating Agreement. See "—Dissolution."

The Operating Agreement limits the business of MV Partners to: (i) holding, maintaining, renewing, exploring, drilling, developing and operating oil and gas leases, lease options, interests, wells, equipment, contracts, easements, unitization agreements, licenses and other assets of MV Partners (together, the "Assets"); (ii) producing, collecting, storing, treating, delivering, marketing, selling or otherwise disposing of oil, gas and related hydrocarbons and minerals from the Assets; (iii) farming-out, selling, abandoning and otherwise disposing of the Assets and other assets of MV Partners; (iv) entering into swaps, options, future contracts and other transactions to hedge or to otherwise minimize the risk associated with the fluctuation of prices to be received by MV Partners from the sale of oil, gas and related hydrocarbons and minerals from the Assets; and (v) taking all such other actions incidental to any of the foregoing as the manager of MV Partners may determine to be necessary and appropriate.

The Operating Agreement expressly prohibits MV Partners from acquiring (i) any gas plant or similar facilities (other than facilities acquired as part of and at the same time as the acquisition of any of the Assets), (ii) any refining facilities or (iii) any transportation facilities except pipelines and gathering systems connecting the Assets with other gathering systems or transmission pipelines, or engaging in the contract drilling business or any other business. In connection with the closing of this offering, the members of MV Partners intend to enter into an amendment to the Operating Agreement that designates the trust as a third-party beneficiary with the right to enforce these restrictions as to which lines of business MV Partners may engage.

At least quarterly, subject to certain exceptions, all cash funds of MV Partners (exclusive of capital contributions, any borrowed funds and any dry hole and bottom hole and similar contributions) which the manager of MV Partners reasonably determines are not needed for the payment of any of its existing or reasonably foreseeable obligations, expenditures and reserves (such reserves not exceeding, in the aggregate, $1.0 million) shall be distributed to the members. Distributions, income, gain, loss, deduction and credits are generally allocated 50% to MV Energy and 50% to VAP-I, subject to certain requirements and regulations required by the Internal Revenue Code.

The Operating Agreement provides that the manager of MV Partners shall generally have full and exclusive power and authority to manage, control, administer and operate the properties, business and affairs of MV Partners in accordance with the Operating Agreement and to do or cause to be done any and all acts deemed by the manager to be necessary or appropriate thereto.

The Operating Agreement designates MV Energy as the initial manager. The Operating Agreement also provides that, with respect to the maintenance, exploration, development and operation of the underlying properties, the manager shall have the standard of care of a prudent and diligent operator. The Operating Agreement further provides that, with respect to the members of MV Partners, the manager shall have the fiduciary duty and other duties imposed under applicable law. The manager must at all times act with integrity and in good faith and utilize its reasonable best efforts in all activities relating to the conduct of the business of MV Partners and in resolving conflicts of interest. During the existence of MV Partners, the manager must devote such time and effort to the business and operations of MV Partners as is necessary to promote fully the interests of MV Partners and the mutual best interests of the members, but is not required to devote full time to MV Partners' business. The manager agrees to retain and have available to it and to MV Partners a professional staff and outside consultants which together will be reasonably adequate in size, experience and competency to discharge properly the duties and functions of the manager under the Operating Agreement and under any applicable operating or other agreements. The operating agreement allows the manager to engage in and possess interests in other business ventures, independently or with others, including the ownership, acquisition, exploration, development, operation and management of oil and gas properties and oil and gas drilling programs and companies similar to or competitive with MV Partners, and, subject to certain exceptions, neither MV Partners nor the members have any right, title or interest in or to such ventures.

The manager is restricted from performing or authorizing certain acts without the consent of all members, including (subject to certain exceptions) the borrowing of money, mortgage or pledging of assets, guaranteeing of third-party payment or performance, disposing of company lease interests, obligating the company with respect to matters outside the scope of its business, merging, consolidating or converting with or into any other entity or compromising or settling any suit or dispute for more than $25,000. In addition, the manager may not cause MV Partners to make or approve any well expenditure, other than certain capitalized reworking costs, or acquire any lease (including acquisitions of increased interest in existing leases) without the advance consent of VAP-I if, but only if, the pro rata share of such well expenditure or acquisition cost that would be born by any indirect owner of VAP-I would exceed $1 million (in which event the consent of VAP-I must first be obtained).

The manager, members and their affiliates are restricted from retaining from or otherwise burdening the interest in any company lease with any overriding royalty interest, net profits interest, carried interest, reversionary interest, production payment or other burden in favor of itself, its officers, directors and employees or any other person, except in connection with an acquisition pursuant to a transaction where an unrelated third party transferring the lease retains such an interest or burden with respect to all of the lease being acquired. Under no circumstances can the manager, any member or any affiliate acquire rights to any separate horizon within or under a lease in which MV Partners has an interest.

The manager has the authority to cause MV Partners to sell any oil or gas produced by MV Partners upon the best terms and conditions available, as determined in good faith by the manager taking into account all relevant circumstances, including but not limited to, price, quality of production, access to markets, minimum purchase guarantees, identity of purchaser, and length of commitment and, in any event, on terms no less favorable to MV Partners than the manager or any affiliate thereof has recently obtained or is obtaining for arm's length sales, exchanges or dispositions of the manager's or such affiliate's production of similar quantity and quality in the same geographic area where MV Partner's production is located.

The Operating Agreement provides that each of Murfin Drilling or Vess Oil will serve as operator on behalf of MV Partners in connection with operations on each lease held by MV Partners included in the underlying properties that it is operating as of the date of the Operating Agreement unless a third person is already designated as operator of that lease or a third party that holds a controlling interest

in that lease will not consent to the designation of Murfin Drilling or Vess Oil as operator. As to those leases that Murfin Drilling or Vess Oil are not designated as operator, the manager will take such actions and exercise such rights and remedies that are reasonably available to it to cause the actual operator to properly develop, maintain and operate such leases. With respect to those leases for which Murfin Drilling or Vess Oil are designated as operator, Murfin Drilling or Vess Oil, as the case may be, shall be entitled to receive the compensation and reimbursement to which the operator is entitled in accordance with the provisions of the Operating Agreement, which sets forth agreed upon charges for certain direct expenses and material furnished to, or transferred from or disposed of by the operator, or any other operating agreement governing the operation of such lease. Murfin Drilling and Vess Oil may not substitute another party as operator or assign their obligations with respect to any lease of MV Partners for which either is designated as operator unless a member makes such a request in connection with the removal of the manager or the members dissolve MV Partners in accordance with the Operating Agreement.

MV Partners pays an overhead fee to Vess Oil and Murfin Drilling to drill, develop and operate the underlying properties on behalf of MV Partners. The overhead fee is based on a monthly charge for each drilling, producing or service well, plus a fee (reduced proportionately for the interest of any non-operators) in connection with the construction and installation of fixed assets, the expansion of fixed assets, and any other project clearly discernible as a fixed asset required for the development and operation of the underlying properties of MV Partners that is determined either (1) on the same terms and conditions as Murfin Drilling or Vess Oil charges unrelated parties, or (2) more than 50% of the members, knowing the material facts of the transaction and the operator's interest, authorize, approve, or ratify. The overhead fee is adjusted annually and will increase or decrease each year based on the Overhead Adjustment Index published by COPAS. MV Partners is also directly responsible for all direct, third-party out-of-pocket expenses reasonably incurred on its behalf, including audit, tax preparation and reserve report related expenses.

MV Partners has agreed to pay the manager a monthly fee of $5,000 for management-related services provided to MV Partners.

The members of MV Partners are not liable for the debts, liabilities, contracts or other obligations of MV Partners under the Operating Agreement except to the extent of such members' share of the assets of MV Partners. Moreover, MV Partners agrees to indemnify and hold harmless the members in the event that they become liable for any debt, liability, contract or other obligation or are directly or indirectly required to make any payments with respect thereto.

Under the Operating Agreement, MV Partners, to the fullest extent permitted by law, shall indemnify and hold harmless the manager, its affiliates, and all of their officers, directors, trustees, partners, members, principals, shareholders, employees and agents (the "Indemnitees") from and against any and all losses, claims, demands, costs, damages, liabilities, expenses, judgments, fines and settlements arising out of or incidental to the business of MV Partners, provided such Indemnitee acted in good faith and in a manner he, she or it reasonably believed to be in, or not opposed to, the interests of MV Partners, and, with respect to any criminal proceeding, had no reason to believe its, his, or her conduct was unlawful. The Indemnitee will not be afforded these protections if it is found that its conduct constituted actual fraud, gross negligence, embezzlement, or willful and wanton misconduct. The satisfaction of any indemnification and any saving harmless shall be satisfied solely out of property of MV Partners, and members are not subject to personal liability by reason of the indemnification provisions. The right to indemnification shall include the right to be paid or reimbursed by MV Partners the reasonable expenses incurred by the Indemnitee who was, is or is threatened to be made a named defendant or respondent in a proceeding in advance of the final disposition of the

proceeding and without any determination as to the Indemnitee's ultimate entitlement to indemnification.

MV Partners may enter into contracts and agreements with the manager, any member and their affiliates for the rendering of services and the sale and lease of supplies and equipment, provided that the transaction is on the same terms and conditions as similar transactions in the market with non-affiliates or a majority of the members, knowing the material facts of the transaction and the member's interest, authorize, approve or ratify the transaction. The members have authorized and approved the right (but not obligation) of MV Partners to sell oil and/or gas to SemGroup, L.P, an Oklahoma limited partnership that is an affiliate of the manager.

The members have the right to: (1) have the books and records of MV Partners kept at its principal office and at all reasonable times to inspect and copy any of them; (2) have on demand true and full information of all things affecting MV Partners and a formal account of the affairs of MV Partners whenever circumstances render it just and reasonable; (3) have dissolution and winding up by decree of court; (4) consult with and advise the Manager; and (5) exercise all of the rights of a member under the Kansas Revised Limited Liability Company Act (the "Kansas LLC Act"). In addition, the members shall be entitled to receive regular monthly, quarterly and annual reports and financial statements of MV Partners together with such additional reports and statements as the members may reasonably request from time to time. The members and their agents and representatives, at any time either during the term of or after termination of MV Partners, have the right to inspect, review and copy geophysical, geological and other similar data and information (or studies, maps, evaluations or reports derived therefrom) which relates to the assets which MV Partners owns or has owned or which has been paid for with MV Partners' funds and to consult with MV Partners' independent certified public accountants and independent petroleum engineers and the manager's technical personnel with respect to company matters. Upon liquidation of MV Partners, copies of all such documents shall be distributed to the members if so requested.

The interest of a member in MV Partners is assignable, but no such assignment may be made if such assignment would result in the violation of any applicable federal or state securities laws, and MV Partners is not be required to recognize any assignment until the instrument conveying such interest has been delivered to the manager for recordation on the books of MV Partners. An assignee of the interest of a member, or any portion thereof, may become a substituted member entitled to all of the rights of the assigning member if, and only if (i) the assignor gives the assignee such right, (ii) members owning more than 50% of the outstanding trust units (other than trust units held by the assigning member), in their sole and absolute discretion, consent to such substitution and (iii) the assignee executes and delivers such instruments, in form and substance reasonably satisfactory to the manager, as the manager may deem necessary or desirable to effect such substitution and to confirm the agreement of the assignee to be bound by all of the terms and provisions of the operating agreement.

A majority of the members may remove the manager with cause and select a new manager to operate and carry on the business and affairs of MV Partners. In order for the members to remove the manager, the manager must have (1) engaged in the commission of fraud, willful or intentional misconduct or gross negligence in the performance of its duties, (2) defaulted in the performance of its obligations under the Operating Agreement to make a distribution of cash or properties due and owing to the members or (3) defaulted in the performance of observation by the manager of any other material agreement, covenant, term, condition or obligation under the Operating Agreement, which

default has continued for not less than 20 days after written notice of such default has been given to the manager by any member. The removal of the manager shall not be effective until a successor manager shall have been selected and agreed to accept the responsibilities of manager. In the event the manager is removed, the incoming manager shall have the right to purchase from the removed manager all of the removed manager's member interest in MV Partners at a price equal to the appraised value thereof.

The Operating Agreement may be changed, modified or amended only by an instrument in writing duly executed by all of the members.

MV Partners will continue as a limited liability company until terminated under the Operating Agreement. MV Partners will dissolve upon: (1) the occurrence of December 31, 2028; (2) the consent in writing of the members; (3) the election of a member by written notice to the other member if at the time such notice is given the manager has committed fraud, willful or intentional misconduct or gross negligence in the performance of its duties, has defaulted in the performance of its obligations to make cash distributions, or has defaulted in the performance or observation of any other material agreement, covenant, term, condition or obligation under the Operating Agreement, which default has continued for not less than 20 days after written notice of such default has been given to the manager by the member; (4) the sale or distribution of all or substantially all of the assets of MV Partners; or (5) the occurrence of any other event which would cause the dissolution of MV Partners under the Kansas LLC Act.

Upon dissolution of MV Partners, the manager will act as the liquidator authorized to wind up MV Partners' affairs or the manager (or VAP-I, if any of the events described in clause (3) above under the heading "—Dissolution" has occurred) will appoint one or more liquidators who shall have full authority to wind up the affairs and make final distribution. The liquidator shall continue to operate the properties of MV Partners with all of the power and authority of the manager necessary or appropriate to liquidate the assets of MV Partners and apply the proceeds of the liquidation as described in the Operating Agreement. Any assets distributed to the members upon liquidation shall be subject to the operating agreements then in effect; provided, however, that if any lease is subject to an operating agreement to which an unaffiliated third person is not a party, such lease shall be subject to a standard form operating agreement as shall be agreed upon by the members. Upon written request made by any member, the liquidator shall sell MV Partners' assets that otherwise would be distributable to such member at the best cash price available therefor and distribute the net proceeds to such member.

We have audited the accompanying balance sheets of MV Partners, LLC (formerly MV Partners, LP) (the "Partnership") as of December 31, 2004 and 2005 and the related statements of earnings, changes in partners' capital (deficit) and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Partnership'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. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of MV Partners, LLC as of December 31, 2004 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

As discussed in note H to the financial statements, in 2003 the Partnership adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations."

Years ended December 31, 2003, 2004 and 2005 and for
the nine-month period ended September 30, 2006 (unaudited)

MV Partners, LLC

NOTES TO FINANCIAL STATEMENTS

For the years ended December 31, 2003, 2004 and 2005
(information for the nine months ended September 30, 2005 and 2006 is unaudited)

A summary of the significant accounting policies consistently applied in the preparation of the accompanying financial statements follows.

MV Partners, LP. (the "Partnership") was organized March 10, 1998 between MV Energy, LLC, the general partner, and TIFD III-X, Inc, the limited partner, to engage in acquisition, exploration, development and production of oil and gas. During 2002, TIFD III-X, Inc. transferred its partnership interest to Aircraft Services Corporation, a related entity. During 2005, Aircraft Services Corporation sold its partnership interest to VAP-I, LLC. The Partnership is a working interest owner in oil and gas properties in Colorado, Oklahoma and Kansas.

Effective August 1, 2006, the Partnership was converted to a limited liability company and the name was changed to MV Partners, LLC. This conversion is not considered a change in reporting entity under accounting principles generally accepted in the United States of America and therefore capital balances in the accompanying financial statements which existed prior to the date of conversion continue to reflect the capital accounts of the entity as a limited partnership. Subsequent to the date of conversion such balances are reflected as members' equity (deficit). The Class A member (former general partner) and Class B member (former limited partner) have substantially identical rights and obligations to one another, including equal sharing of revenues and expenses. The Class A member serves as the manager of MV Partners, LLC. MV Partners, LLC is scheduled to be dissolved on December 31, 2028.

Partnership revenues and costs were generally allocated 95% to the limited partner and 5% to the general partner prior to Payout 1 except for hedging gains and losses which were generally allocated 100% to the limited partner. Payout 1 occurred on the last day of the month during which the total cash distributions paid to the limited partner discounted at 11% annually compounded monthly equaled the capital contributions paid by the limited partner. Subsequent to Payout 1 and prior to Payout 2, revenues and costs were to be allocated 60% to the limited partner and 40% to the general partner with Payout 2 occurring the last day of the month during which the total cash distribution paid to the limited partner discounted at 15% annually compounded monthly equaled the capital contributions paid by the limited partner. After Payout 2, revenues and costs are allocated 50% to the limited partner and 50% to the general partner. As a result of the distribution made to the limited partner during December 2005, both Payout 1 and Payout 2 occurred. The occurrence of Payout 1 and Payout 2 was effective December 31, 2005, thus revenues and costs were allocated 95% to the limited partner and 5% to the general partner throughout 2005. As a result of Payout 1 and 2 occurring during 2005 as described above, future cash distributions will be allocated 50% to the general partner and 50% to the limited partner. The partners have agreed to make a special reallocation as of December 31, 2005 to equalize the general partner and limited partner capital accounts. Such reallocation is shown in the accompanying statements of changes in partners' capital (deficit).

The financial information as of September 30, 2006 and for the nine months ended September 30, 2005 and 2006 is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the results of the interim periods, except that the results of operations for the nine months ended September 30,

2006 include a charge for $592,708 that represents ad valorem tax expense for the prior year that was not accrued at December 31, 2005. MV's management does not expect that the correction of this error will be material to the financial statements for the year ended December 31, 2006. The results of operations for the nine month period ended September 30, 2006 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2006.

The Partnership follows the successful efforts method of accounting for oil and gas property acquisition, exploration, development and production activities.

Oil and gas property acquisition costs, exploration well costs and development well costs are capitalized as incurred. Net capitalized costs of unproven property and exploration well costs are reclassified as proved property and well costs when related proved reserves are found. If an exploration well is unsuccessful in finding proved reserves, the capitalized well costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs, and the costs of carrying unproved property are charged to exploration expense as incurred.

Producing leasehold costs are amortized by property using the unit-of-production method based upon total estimated proved reserves. Capitalized exploration well costs and development costs and lease equipment (plus estimated future equipment dismantlement, surface restoration, and property abandonment costs, net of equipment salvage values) are amortized by property using the unit-of-production method based on estimated proved developed reserves. Due to uncertainties inherent in this estimation process, it is at least reasonably possible that reserve quantities will be revised in the near term.

The Partnership reviews its long-lived assets, including its oil and gas properties, for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. The Partnership determines whether an impairment has occurred by estimating the undiscounted expected future net cash flows of its oil and gas properties at a field level and compares such cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. For those oil and gas properties for which the carrying amount exceeds the undiscounted estimated future cash flows, an impairment is determined to exist. The carrying amount of such properties is adjusted to their estimated net fair value based on relevant market information or discounted cash flows.

Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to the accumulated depreciation, depletion and amortization reserve. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major replacements and renewals are capitalized. All properties are stated at cost.

Revenues from the sale of oil and gas production are recognized as oil and gas is produced and sold.

The Partnership uses swap and collar agreements to mitigate the effects of fluctuations in the prices of crude oil. These agreements involve the exchange of amounts based on a fluctuating oil price for amounts based on a fixed oil price over the life of the agreement, without an exchange of the notional amount upon which the payments are based. The differential paid or received is recognized as an adjustment of oil and gas revenue.

The Partnership follows Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Partnership accounts for the derivatives as follows:

The swap agreements qualify as cash flow hedges. As such, all of the Partnership's swap agreements are recorded on the balance sheet at fair value. For all derivatives designated as cash flow hedges, the effective portion of the gain or loss on the derivative instrument is recorded as a component of other comprehensive income (loss) and reclassified into earnings as the underlying hedged item effects earnings. The ineffective portion of the unrealized gain or loss on the derivative instrument is charged directly to earnings.

The Partnership enters into collar agreements. Under these agreements, the Partnership pays the counterparty if oil prices exceed a defined ceiling price and the counterparty pays the Partnership if oil prices are less than a defined floor price. These agreements are recorded on the balance sheet at fair value and the resulting gains or losses are recorded in earnings.

The Partnership's trade accounts receivable are due primarily from two crude oil dealers. State law requires that receipts for crude oil sales are paid within one month following the related production and that receipts for natural gas sales are paid within two months following the related production. The Partnership considers the trade receivables to be fully collectible and has historically not experienced any collection issues. Accordingly, an allowance for doubtful accounts is not required. If amounts become uncollectible, they will be charged to operations when that determination is made.

For purposes of the statements of cash flows, the Partnership considers all highly liquid investments purchased with a maturity of three months or less to be cash equivalents. Cash equivalents are stated at cost which approximates market value.

Deferred offering costs consist of legal, accounting, engineering and other costs associated with the proposed sale of a term net profits interest in the oil and natural gas properties of the Partnership. If the sale is successful, these costs will be netted against the offering proceeds. If the sale is unsuccessful, these costs will be reclassified to operations.

In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates affecting these financial statements include estimates for quantities of proved oil and gas reserves, asset retirement obligations and others, and are subject to change.

Federal and state income taxes are the liability of the individual partners; accordingly, the financial statements do not include any provision for federal or state income taxes.

Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations," requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred. The liability is measured at discounted fair value and is adjusted to its present value in subsequent periods as accretion expense is recorded. Such accretion expense is included in depreciation, depletion and amortization in the accompanying statements of earnings. The corresponding asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset and amortized over the asset's useful life. The Partnership's asset retirement obligations are primarily associated with the plugging of abandoned oil wells. SFAS No. 143 was effective for the Partnership January 1, 2003 and it was adopted on that date.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. SFAS No. 154 supercedes SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements, and APB Opinion No. 20, Accounting Changes. SFAS No. 154 requires, unless impracticable, retrospective application to prior periods' financial statements of changes in accounting principle. The provisions of SFAS No. 154 also require that a change in depreciation, amortization, or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. SFAS No. 154 is effective for all accounting changes made in fiscal years beginning after December 15, 2005.

for a one-time cumulative effect transition adjustment. We have applied the guidance of SAB No. 108 for all periods presented.

	December 31,
	December 31,				September 30, 2006
	2004		2005		September 30, 2006
					(unaudited)
Producing leaseholds	$	65,611,135	$	65,180,888	$	64,951,478
Lease equipment		22,661,044		24,260,772		25,139,964
Well development costs		3,200,838		3,581,617		3,712,818

		91,473,017		93,023,277		93,804,260
Less accumulated depreciation, depreciation and amortization		34,616,375		37,739,074		39,770,555

Net oil and gas properties	$	56,856,642	$	55,284,203	$	54,033,705

The Partnership's oil and gas activities are conducted entirely in the United States. Costs incurred in oil and gas producing activities for the years ended December 31 and for the nine months ended September 30 are as follows:

		December 31,						September 30,
		2003		2004		2005		2005		2006
								(unaudited)		(unaudited)
Property acquisition costs		$	1,212,418	$	1,428,765	$	2,222,876	$	1,551,889	$	1,100,315
Development costs			172,427		297,140		380,778		350,087		131,201

	Total	$	1,384,845	$	1,725,905	$	2,603,654	$	1,901,976	$	1,231,516

The results of operations for oil and gas producing activities, excluding corporate overhead and interest costs for the years ended December 31 and for the nine months ended September 30 are as follows:

Lease operating expense includes those costs incurred to operate and maintain productive wells and related equipment and include costs such as labor, repairs and maintenance, materials, supplies, fuel consumed and insurance.

Depreciation, depletion and amortization include costs associated with capitalized acquisitions and development costs.

During 2003, 2004 and part of 2005, the Partnership had a revolving note payable to a bank with a maximum balance outstanding of $25,000,000. The note's interest rate was adjusted quarterly based upon the bank's base rate plus an applicable margin which was based upon the Partnership's earnings before interest, taxes, depreciation and amortization ("EBITDA") for the prior quarter. The note's effective rate at December 31, 2003 and 2004 was 2.53% and 2.79%, respectively. The note was collateralized by a first priority mortgage, security interest and assignment of production on all of the Partnership's oil and gas properties.

At September 30, 2005, the Partnership refinanced the note payable with a finance company for $25,000,000. The note's interest rate was adjusted quarterly based upon the bank's base rate plus an applicable margin which was based upon the Partnership's EBITDA, as defined in the agreement, for the prior quarter. The note was collateralized by a first priority mortgage, security interest and assignment of production on all of the Partnership's oil and gas properties.

On December 21, 2005, through a series of transactions in connection with the Limited Partner ownership change (see Note G), the Partnership refinanced their debt with another lender and borrowed an additional $65,000,000, bringing the total borrowings to $90,000,000. The note's interest rate is adjusted quarterly based upon the bank's base rate plus an applicable margin which is based upon the Partnership's EBITDA, as defined in the agreement, for the prior quarter. The note's effective rate at December 31, 2005 was 6.60%. Interest is payable quarterly. The note is collateralized by a first priority mortgage, security interest and assignment of production on all of the Partnership's oil and gas properties and matures December 19, 2008. Below are further details of the Partnership's credit agreement with the primary lender at December 31, 2005.

The Partnership's initial borrowing base is $95 million. The borrowing base is reduced to $90 million on July 1, 2006 and $85 million on January 1, 2007. The borrowing base thereafter is determined periodically by the lender. The Partnership must maintain $5 million of availability under the borrowing base at all times and has classified $10 million of the outstanding borrowings as a current liability at December 31, 2005. The Partnership pays a fee of 0.125% to 0.375% on the unused portion of the borrowing base depending upon the portion of the borrowing base utilized by the Partnership.

The credit agreement with the Partnership's primary lender provides for the issuance of letters of credit. When the lender issues a letter of credit, an initial fee is charged and a quarterly fee is charged for the amount available on the letter of credit. If the Partnership's primary lender honors a letter of credit, the lender may require immediate collateralization of cash to cover such drawing and interest will be due based upon the Eurodollar rate plus an applicable margin of 1.00% to 1.75% depending upon the amount of the Partnership's borrowing base currently being used. At December 31, 2005, the Partnership did not have any outstanding Letters of Credit with the Partnership's primary lender.

The Partnership has a revolving credit facility. This revolving facility is completely discretionary by the lender. The swing line loans are based upon the Bank's base rate plus an applicable margin of 0% to 0.75% based upon the unused portion of the borrowing base. At December 31, 2005, the Partnership did not have an outstanding balance on the Swing Line Loan.

The total of all commitments for the Borrowing Base, Letters of Credit and Swing Line Loan can not exceed $200 million.

The Partnership is subject to certain financial covenants associated with the borrowings including current ratio and interest coverage ratio requirements. In addition, the Partnership is required to enter into swap agreements in the future to cover 90% of the next three years of estimated production with a fixed price per barrel of a minimum of $55. The bank determined compliance with the 90% hedging requirement based on the engineering estimates in existence at the time the financial covenants were established. The bank has not required the Partnership to increase the hedged quantities as revised engineering estimates have been prepared. The Partnership is in compliance with the required debt covenants at December 31, 2005 and September 30, 2006 (unaudited).

The Partnership uses swap and collar agreements to reduce the effects of fluctuations in crude oil prices. At December 31, 2005, the Partnership's hedging activities included swap agreements maturing through the year 2008 (2010 at September 30, 2006 (unaudited)). Under these arrangements, the Partnership will effectively receive fixed prices for the oil production hedged. The price source for the

commodity type hedge is the New York Mercantile Exchange for the monthly activity. The agreements covered 838,427 barrels, 830,520 barrels and 771,368 barrels of crude oil production in the years ended December 31, 2003, 2004 and 2005, respectively. The Partnership produced 1,197,847, 1,126,812 and 1,057,906 barrels of crude oil in 2003, 2004 and 2005, respectively (unaudited). The Partnership had agreements covering 585,213 barrels and 654,615 barrels of crude oil production in the nine months ended September 30, 2005 and 2006, respectively (unaudited). The Partnership produced 788,223 barrels and 771,230 barrels of crude oil in the nine months ended September 30, 2005 and 2006 respectively (unaudited).

Gains and losses on the hedging transactions are recognized when the hedged production is sold and, through September 29, 2005, allocated 100% to the limited partner. Subsequent to September 29, 2005, the gains and losses on the hedging transaction were allocated as shown in Note I. The Partnership recorded a hedging loss of $7,442,801, $14,402,644 and $21,470,799 in 2003, 2004 and 2005, respectively, which is reflected as a reduction of oil and gas sales in the statements of earnings. The Partnership reduced oil and gas sales to record hedging losses of $16,551,249 and $14,267,664 for the nine months ended September 30, 2005 and 2006, respectively (unaudited). In addition, the Partnership has recorded income of $59,539 for the year ended December 31, 2003, a loss of $848,072 for the year ended December 31, 2005 and a loss of $863,017 for the nine months ended September 30, 2006 (unaudited), which reflects the ineffective portion of the unrealized gain or loss on the hedge at December 31, 2003 and 2005 and September 30, 2006, respectively. These gains and losses have also been reflected as an increase or decrease of oil and gas sales in the December 31, 2003 and 2005 and the September 30, 2006 statements of earnings.

The notional volume and fair market value of outstanding swap agreements at December 31, 2004 and 2005 and September 30, 2006 (unaudited) are as follows:

Year	Notional volume	Fixed price		Fair value
2006	359,565 Bbls 168,000 Bbls 335,320 Bbls	$	33.60 59.14-59.60 63.96	$	(10,481,507 (644,937 258,243	) )
2007	192,000 Bbls 495,000 Bbls		58.25-58.60 63.16-65.12		(999,696 54,918	)
2008	374,000 Bbls 360,000 Bbls 45,000 Bbls		56.39-56.58 60.70 62.99		(2,308,106 (869,640 24,755	) )

				$	(14,965,970	)

Year	Notional volume	Fixed price		Fair value
2006	42,000 Bbls 166,270 Bbls	$	59.14-59.60 63.96	$	(198,946 (6,591	) )
2007	192,000 Bbls 495,000 Bbls		58.25-58.60 63.16-65.12		(1,781,677 (1,815,409	) )
2008	374,000 Bbls 360,000 Bbls 45,000 Bbls		56.39-56.58 60.70 62.99		(4,172,568 (2,630,970 (241,965	) ) )
2009	480,000 Bbls 198,000 Bbls		64.30-64.60 70.57		(1,153,904 553,354	)
2010	444,000 Bbls 193,800 Bbls		63.30-63.80 68.65		(746,109 476,619	)

				$	(11,718,166	)

During the year ending December 31, 2005, the Partnership has also entered into a collar transaction covering 120,000 barrels of oil during 2007 under which the Partnership will receive payments if oil prices fall below $61 per barrel or make payments if oil prices rise above $68 per barrel. The collar had a nominal fair value at December 31, 2005 and ($328,215) at September 30, 2006 (unaudited), which is included in oil swap agreements in the accompanying balance sheets. The resulting loss of $328,215 for the nine months ended September 30, 2006 (unaudited) is reflected as a decrease to oil and gas sales in the accompanying statement of earnings.

The Partnership's swap and collar agreements expose it to market and credit risks that may at times be concentrated with certain counterparties or groups of counterparties. Counterparties to the Partnership's financial instruments are major financial institutions and an energy company, and their credit worthiness is subject to continuing review, however, full performance is anticipated. The carrying values of the Partnership's other financial instruments (cash equivalents and note payable) approximate their fair values. The estimated amount of unrealized loss at December 31, 2005 expected to be reclassified into earnings in the next 12 months is $10,544,349.

MV Energy, LLC, the sole manager, is comprised of two independent oil companies who serve as the operator of the oil and gas wells of the Partnership. Below is a summary of the transactions that occurred between the Partnership and the operators:

	December 31,						September 30,
	2003		2004		2005		2005		2006
							(unaudited)		(unaudited)
Lease operating expense incurred	$	12,801,668	$	12,908,370	$	13,965,723	$	10,292,026	$	12,870,788
Capitalized lease equipment and producing leaseholds costs incurred		1,004,679		1,277,268		1,863,349		1,376,171		911,369
Payment of well development costs		172,427		297,140		380,778		350,087		131,201
Payment of management fees		60,000		60,000		60,000		45,000		45,000
Sale of natural gas		554,270		549,128		542,501		349,711		413,205
Purchase of working interest		—		70,575		—		—		—

The members of the Partnership's sole manager, MV Energy, LLC and certain members of the Partnership's limited partner, VAP-I, LLC, have a minority ownership interest in two of the Partnership's customers.

		December 31,						September 30,
		2003		2004		2005		2005		2006
								(unaudited)		(unaudited)
Sales(1)
	Eaglwing, L.P.	$	20,321,668	$	26,756,152	$	35,290,153	$	25,738,338	$	37,414,703
	SemCrude, L.P.		10,445,956		13,764,683		17,628,316		12,263,152		8,356,274

		$	30,767,624	$	40,520,835	$	52,918,469	$	38,001,490	$	45,770,977

Trade receivables
	Eaglwing, L.P.	$	1,724,229	$	2,362,788	$	2,902,791	$	3,279,699	$	4,635,251
	SemCrude, L.P.		879,529		1,214,575		1,624,013		1,507,962		5,597

		$	2,603,758	$	3,577,363	$	4,526,804	$	4,787,661	$	4,640,848

A summary of the Partnership's outstanding swap agreements with SemCrude, L.P. are as follows: (The Partnership had no related party contracts at December 31, 2004.)

At December 31, 2005 and September 30, 2006 (unaudited), the Partnership had an outstanding collar transaction with SemCrude, L.P. covering 120,000 barrels of oil during 2007 under which the Partnership will receive payments if oil prices fall below $61 per barrel or make payments if oil prices rise above $68 per barrel. The fair value of the collar was nominal at December 31, 2005 and ($328,215) at September 30, 2006 (unaudited).

Financial instruments, which potentially subject the Partnership to credit risk, consist primarily of cash, cash equivalents, trade receivables and swap agreements.

The Partnership maintains cash and cash equivalents with one financial institution. At times, such amounts may exceed the F.D.I.C. limits. The Partnership places its cash and cash equivalents with a high credit quality financial institution and believes that no significant concentration of credit risk exists with respect to these cash investments.

Trade receivables subject the Partnership to the potential for credit risk with customers. Approximately 90%, 91% and 91% of the Partnership's trade receivables balance at December 31, 2004 and 2005 and September 30, 2006 (unaudited), respectively, was represented by two customers. Management continually evaluates the credit worthiness of the customers and believes full payment will be made.

The Partnership has entered into certain swap agreements as discussed in Note D.

During 2005, Aircraft Services Corporation sold its limited partnership interest to a newly formed entity—VAP-I, LLC ("VAP"). VAP is an LLC with five members, one of which is MV Energy, LLC, which has a 37.4% ownership interest.

In connection with the transaction, the Partnership obtained a loan on December 21, 2005 from a new lender for $90,000,000. The proceeds from the loan were used to make a cash distribution to VAP of $64,656,706 and to pay off previously existing debt of $25,000,000. The Partnership also made a distribution to MV Energy, LLC in the form of a note payable for $24,896,844. MV Energy then contributed $12,448,422 of the note to VAP for its ownership percentage in VAP and contributed the

remaining $12,448,422 of the note back to the Partnership as a capital contribution. VAP also contributed their $12,448,422 note to the Partnership as a capital contribution.

The Partnership adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which the liability is incurred. The liability is measured at discounted fair value and is adjusted to its present value in subsequent periods as accretion expense is recorded. Such accretion expense is included in depreciation, depletion and amortization in the accompanying statements of earnings. The corresponding asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset and amortized over the asset's useful life. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost. The Partnership's asset retirement obligations are primarily associated with the plugging and abandoning of oil and gas properties.

The estimated plug and abandon dates change routinely based upon additional engineering data and changes in the price of oil impacting the date when the well is no longer economically feasible to operate. Those changes in the plug and abandon dates are remeasured on an annual basis based upon the then current plug and abandon dates of the wells using the original measurement date rates. Asset retirement obligations on new wells drilled are calculated on their initial measurement date based upon the then current interest rate environment.

Prior to the adoption of SFAS No. 143, the Partnership determined that the salvage value from well equipment would approximately offset the cost of plugging and abandoning the well and therefore had not established salvage values on the Partnership's equipment, neither had it established an asset retirement obligation. In connection with the adoption of SFAS No. 143, the Partnership also established salvage values on its well equipment and restated accumulated depreciation on such equipment. This resulted in a net increase to equipment of $3,381,793 as of January 1, 2003. In addition, the Partnership recorded a net asset retirement cost, the balance of which was $4,947,363 at January 1, 2003 ($7,469,207 of costs less accumulated depletion of $2,521,844) for a total increase to assets at January 1, 2003 of $8,329,156. The Partnership also recorded an asset retirement obligation, the balance of which was $8,239,487 as of January 1, 2003, resulting in a cumulative effect of change in accounting principle of $89,669 in 2003.

The activity in the asset retirement obligation during the years ended December 31 and for the period ended September 30, 2006 is as follows:

	December 31,
	December 31,						September 30, 2006
	2004			2005			September 30, 2006
							(unaudited)
Asset retirement obligation—beginning of period	$	7,708,729		$	7,868,746		$	7,695,180
Liabilities incurred during the period		48,508			327,943			49,740
Liabilities settled during the period		(62,925	)		(185,123	)		(127,476	)
Decrease in asset retirement obligation due to changes in timing of estimated cash flows		(65,988	)		(553,540	)		(372,520	)
Accretion expense		240,422			237,154			180,150

Asset retirement obligation—end of period	$	7,868,746		$	7,695,180		$	7,425,074

In conjunction with VAP purchasing the limited partnership interest as described in Note G, all parties agreed to the following:

As part of the Contribution Agreement for the formation of VAP, all parties agreed the hedging gains and losses would no longer be 100% allocated to the limited partner. Effective September 29, 2005, swap gains and losses are allocated in the same manner as other revenues and expenses.

The distribution made on December 21, 2005 (see Note G) was enough to reach Payout 1 and Payout 2, as defined in the partnership agreement. This caused a change in the sharing of future distributions to 50% limited partner and 50% general partner beginning with the last day of the month that the distribution occurred (December 31, 2005). The distribution, as described above, was in excess of the amounts in partners' capital, and in effect, represented a distribution of future earnings. Rather than continuing to allocate future earnings based on pre Payout 1 and 2 allocations until the partner capital accounts are equalized, the partners agreed to make a special reallocation of partners' capital for financial statement purposes as of December 31, 2005 to equalize the general partner and limited partner capital accounts. Such reallocation is shown in the accompanying statements of changes in partners' capital (deficit). As a result, revenues and expenses subsequent to December 31, 2005 will be allocated 50% to the general partner and 50% to the limited partner. For income tax purposes, the partnership intends to continue to allocate future earnings based on pre Payout 1 and 2 allocations until the partner accounts are equalized for tax purposes.

The estimates of proved reserves and related valuations were based on the reports of Cawley, Gillespie & Associates, Inc., independent petroleum and geological engineers, and the contract property management engineering staff of the sole manager of the Partnership, in accordance with the provisions of SFAS No. 69, Disclosures about Oil and Gas Producing Activities. Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" natural gas, natural gas liquids and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.

The Partnerships' oil and gas reserves are attributable solely to properties within the United States. A summary of the Partnerships' changes in quantities of proved oil and gas reserves for the years ended December 31, 2003, 2004 and 2005 are as follows:

	Oil (Bbls)		Gas (Mcf)		NGL (Bbls)
Balance at January 1, 2003	16,472,230		2,552,088		143,123
Revisions of previous estimates	307,789		(910,403	)	(26,364	)
Extensions and discoveries	13,608		—		—
Production	(1,197,847	)	(116,122	)	(2,734	)

Balance at December 31, 2003	15,595,780		1,525,563		114,025
Revisions of previous estimates	1,444,657		(282,855	)	(875	)
Purchase of minerals in place	16,127		—		—
Extensions and discoveries	846		—		—
Sales of minerals in place	(15,448	)	—		—
Production	(1,126,812	)	(103,540	)	(4,674	)

Balance at December 31, 2004	15,915,150		1,139,168		108,476
Revisions of previous estimates(1)	3,053,651		309,242		5,492
Sales of minerals in place	(5,155	)	—		—
Production	(1,057,906	)	(89,117	)	(4,575	)

Balance at December 31, 2005	17,905,740		1,359,293		109,393

Proved developed reserves:
December 31, 2003	14,913,460		1,348,538		114,025

December 31, 2004	15,317,009		1,139,168		108,476

December 31, 2005	15,888,099		1,062,701		109,393

The following information was developed using procedures prescribed by SFAS No. 69. The standardized measure of discounted future net cash flows should not be viewed as representative of the Partnership's current value. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating the Partnership or its performance.

The Partnership believes that, in reviewing the information that follows, the following factors should be taken into account:

Under the standardized measure, future cash inflows were estimated by applying year-end oil and gas prices, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open hedge and other derivative positions (see Note D—Financial Instruments). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs to arrive at net cash flows. Use of a 10% discount rate and year-end prices and costs are required by SFAS No. 69.

		2003			2004			2005
Future cash inflows		$	486,589,300		$	669,493,400		$	1,050,284,000
Future costs
	Production		(247,548,255	)		(299,008,800	)		(395,987,600	)
	Development and abandonment		(3,077,645	)		(3,260,000	)		(16,513,600	)

Future net cash flows			235,963,400			367,224,600			637,782,800
Less effect of 10% discount factor			(114,627,000	)		(185,616,900	)		(333,250,300	)

Standardized measure of discounted future net cash flows		$	121,336,400		$	181,607,700		$	304,532,500

Future cash flows as shown above were reported without consideration for the effects of hedge and other derivative transactions outstanding at each period end. If the effects of hedge and other derivative transactions were included in the computation, then future cash flows would have decreased by $9,816,900, $14,175,700 and $7,655,100 in 2003, 2004 and 2005, respectively.

The changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:

		2003			2004			2005
Standardized measure—beginning of year		$	126,210,000		$	121,336,400		$	181,607,700
	Sales of oil and gas produced, net of production costs		(20,559,984	)		(29,940,739	)		(41,115,792	)
	Net change in prices and production costs		4,428,376			57,356,656			94,091,763
	Extensions and discoveries		132,238			17,355			—
	Changes in estimated future development costs		330,065			(349,338	)		(11,516,747	)
	Development costs incurred during the period which reduce future development costs		120,000			165,000			—
	Revisions of previous quantity estimates		1,084,814			15,933,831			53,096,437
	Accretion of discount		12,621,000			12,133,640			18,160,770
	Purchase of reserves in place		—			146,696			—
	Sales of reserves in place		—			(136,766	)		(22,001	)
	Changes in production rates and other		(3,030,109	)		4,944,965			10,230,370

Standardized measure—end of year		$	121,336,400		$	181,607,700		$	304,532,500

Average prices in effect at December 31, 2003, 2004 and 2005 used in determining future net revenues related to the standardized measure calculation are as follows:

The following unaudited pro forma financial statements have been prepared to illustrate the conveyance of a net profits interest in all the underlying properties by MV Partners to the Trust and the payment of long-term debt obligations by MV Partners. The unaudited pro forma balance sheet is presented as of September 30, 2006, giving effect to an issuance of 11,500,000 trust units at $20.00 per unit, the net profits interest conveyance and the payment of MV Partners' long-term debt obligations as if they occurred on September 30, 2006. The unaudited pro forma statements of earnings present the historical statements of earnings of MV Partners for the year ended December 31, 2005 and the nine months ended September 30, 2006, giving effect to the net profits interest conveyance and payment of MV Partners' long-term debt obligations as if they occurred as of January 1, 2005 reflecting only pro forma adjustments expected to have a continuing impact on the combined results.

These unaudited pro forma financial statements are for informational purposes only. They do not purport to present the results that would have actually occurred had the unit offering, net profits interest conveyance, and payment of long-term obligations been completed on the assumed dates or for the periods presented. Moreover, they do not purport to project MV Partners' financial position or results of operations for any future date or period.

To produce the pro forma financial information, management made certain estimates. These estimates are based on the most recently available information. To the extent there are significant changes in these amounts, the assumptions and estimates herein could change significantly. The unaudited pro forma financial statements should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations of MV Partners, LLC" and the audited historical financial statements of MV Partners, LLC included in this prospectus and elsewhere in the registration statement.

The accompanying notes are an integral part of these unaudited pro forma financial statements.

MV Partners will convey the net profits interest in oil and natural gas producing properties located in the States of Kansas and Colorado to the MV Oil Trust (the "Trust"). 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 and the underlying properties will revert back to MV Partners on the later to occur of (1) June 30, 2026, or (2) when 14.4 MMBoe have been produced from the underlying properties and sold.

The proceeds of the offering will be used to repay approximately $58.0 million of indebtedness of MV Partners under its bank credit facility and to distribute the remaining $80.0 million to its members.

The unaudited pro forma balance sheet assumes the issuance of 11,500,000 trust units at $20.00 per unit and estimated direct transaction costs to be incurred by MV Partners of approximately $12.0 million (comprised of underwriter, legal, accounting and other fees). As of September 30, 2006, MV Partners had incurred $981,055 of these direct transaction costs.

MV Partners will sell 7,500,000 of the trust units to the public for cash of $150.0 million and recognize a deferred gain of $116.1 million. The deferred gain will be recognized in income over the life of the net profits interest based on production. MV Partners will also sell 4,000,000 of the trust units to its members in exchange for a cash down payment of $8.0 million and notes receivable for $72.0 million in the aggregate. The notes will be paid off in forty (40) quarterly payments beginning July 2007, including interest at 7.25%. The notes will be collateralized by each member's ownership interest in MV Partners. In accordance with accounting rules for transactions among related parties, the notes receivable were recorded at the historical carrying value of the trust units sold to the members and no gain on sale has been reflected. The excess of payments over the historical carrying value will be recorded as capital contributions by the members.

MV Partners has entered into hedge and other derivative arrangements with institutional third parties with respect to the volumes of oil production for the periods covered by these pro forma statements and the years following until 2010 such that MV Partners would be entitled to receive payments from the counterparties in the event that reference prices for oil contracts traded on NYMEX for the periods covered are less than the fixed prices specified for the hedge and other derivatives. MV Partners will also be required to make payments to the counterparties in the event that reference prices for oil contracts traded on NYMEX for the periods covered are more than the fixed prices specified for the hedge and other derivatives. Although these hedge and other derivative arrangements will not be directly dedicated or pledged to the Trust, MV Partners expects that payments received or made by it under these hedge and other derivative arrangements will affect its financial obligations to make payments to the Trust. The effects of these hedge and other derivative arrangements, if any, are reflected in these unaudited pro forma financial statements.

Pro forma adjustments are necessary to reflect the issuance of the Trust units, the conveyance of the net profits interest, the sale of trust units and the payment of MV Partners' long-term obligations and distributions using proceeds from the offering. The pro forma adjustments included in the unaudited pro forma balance sheet are as follows:

The pro forma adjustments included in the unaudited pro forma statements of earnings are as follows:

As requested, we are submitting our estimates of total proved reserves and forecasts of economics attributable to MV Partners, LLC ("Company") interests in certain oil and gas properties located in Kansas and Colorado. This report includes results for the SEC price scenario and includes the hedge revenue gain or loss. A composite summary of the proved reserves is presented below.

The discounted cash flow value shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc.

This report is divided into four main sections: Summary, Proved Developed Producing ("PDP"), Proved Developed Non-Producing ("PDNP") and Proved Undeveloped ("PUD"). Within each reserve category section are grand total Table I's and Table II summaries. The Table I's present composite reserve estimates and economic forecasts for the particular reserve category. Following the tables are Table II "oneline" summaries that present estimates of ultimate recovery, gross and net reserves, ownership, revenue, expenses, investments, net income and discounted cash flow ("DCF") for the individual properties that make up the corresponding Table I. The properties in each Table II are sorted based on DCF.

For a more detailed description of the report layout, please refer to the Table of Contents following this letter. The data presented in each Table I is explained in page 1 of the Appendix. The methods employed in estimating reserves are described in page 2 of the Appendix.

As requested, oil and gas prices were adjusted to the NYMEX June 30^th, 2006 closing WTI Cushing oil price of $73.93 per BBL and Henry Hub natural gas price of $6.104 per MMBTU. Prices were not escalated in accordance with Securities and Exchange Commission ("SEC") guidelines.

Oil price differentials were forecast at -$3.25 per BBL for all properties and were not escalated. Gas and NGL price differentials were forecast on a per property basis as provided by your office and were also not escalated. Gas 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.

A "Hedge Position" case was included to model the gain/(loss) in revenue due to the Company's current pricing hedge position. The hedge forecast is located in "Hedge Revenue" (column 15) in the attached tables. A summary of the annual gain/(loss) in revenue is presented below:

Lease operating expenses, workover expenses, COPAS overhead charges and investments were forecast on a per property basis as furnished by your office. Workover expenses were forecast at $73.82 per month per net well for all producing properties. Expenses and investments were held constant in accordance with SEC 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 2.5% of total revenue were applied to each property as provided by your office. Oil and gas conservation tax rates were applied to all Kansas properties at rates of $0.0547 per BBL and $0.00913 per MCF, respectively.

An on-site field inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined, nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included except as noted above.

The proved reserve classifications used herein conform to the criteria of the Securities and Exchange Commission as defined in page 3 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties in effect on the effective date, except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions have not been considered. All reserve estimates represent our best judgment based on data available at the time of preparation, and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts

The reserve estimates and forecasts were based upon interpretations of factual data furnished by your office. Production data, ownership information, price differentials, expense data and tax details were furnished by MV Partners, LLC, and were accepted as furnished. To some extent, information from public records was used to check and/or supplement these data. The basic engineering and geological data were utilized subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data.

This report was prepared for the exclusive use of MV Partners, LLC. Third parties should not rely on it without the written consent of the above and Cawley, Gillespie & Associates, Inc. We are independent registered professional engineers and geologists. We do not own an interest in the properties or MV Partners, LLC and are not employed on a contingent basis. Our work papers and related data are available for inspection and review by authorized, interested parties.

Until , 2007 (25 days after the date of this prospectus), federal securities laws may require all dealers that effect transactions in the trust units, whether or not participating in this offering, to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the NASD filing and the NYSE listing fee, the amounts set forth below are estimates.

Registration fee		$	18,458
NASD filing fee			23,500
NYSE listing fee			73,500
Printing and engraving expenses			350,000
Fees and expenses of legal counsel			650,000
Accounting fees and expenses			550,000
Transfer agent and registrar fees			5,000
Trustee fees and expenses			37,500
Miscellaneous			150,000

	Total	$	1,857,958

The trust agreement provides that the trustee and its officers, agents and employees shall be indemnified from the assets of the trust against and from any and all liabilities, expenses, claims, damages or loss incurred by it individually or as trustee in the administration of the trust and the trust assets, including, without limitation, any liability, expenses, claims, damages or loss arising out of or in connection with any liability under environmental laws, or in the doing of any act done or performed or omission occurring on account of it being trustee or acting in such capacity, except such liability, expense, claims, damages or loss as to which it is liable under the trust agreement. In this regard, the trustee shall be liable only for its own fraud or gross negligence or for acts or omissions in bad faith and shall not be liable for any act or omission of any agent or employee unless the trustee has acted in bad faith or with gross negligence in the selection and retention of such agent or employee. The trustee is entitled to indemnification from the assets of the trust and shall have a lien on the assets of the trust to secure it for the foregoing indemnification.

Under the MV Partners, LLC operating agreement and subject to specified limitations, MV Energy, LLC shall not be liable, responsible or accountable in damages or otherwise to MV Partners, LLC or its members for, and MV Partners, LLC shall indemnify and hold harmless MV Energy, LLC from any costs, expenses, losses or damages (including attorneys' fees and expenses, court costs, judgments and amounts paid in settlement) incurred by reason of its being the sole manager of MV Partners, LLC. Reference is also made to the Underwriting Agreement to be filed as an exhibit to this registration statement in which MV Partners, LLC and its affiliates will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the operating agreement, Section 17 7670 of the Kansas General Corporation Code empowers a Kansas limited liability company to indemnify and hold harmless any member or manager or other persons from and against all claims and demands whatsoever.

In connection with the preparation and filing of any shelf registration statement, MV Oil Trust will indemnify MV Partners, LLC and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or

prospectus. MV Oil Trust will bear all costs and expenses incidental to any shelf registration statement, excluding any underwriting discounts and fees.

No financial statement schedules are required to be included herewith or they have been omitted because the information required to be set forth therein is not applicable.

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Wichita, State of Kansas, on December 18, 2006.

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed below by the following persons in the capacities and on the dates indicated.

Amendment No. 4 to Form S-1 MV Oil Trust (Exact Name of co-registrant as specified in its charter)		Amendment No. 4 to Form S-1 MV Partners, LLC (Exact Name of co-registrant as specified in its charter)
Delaware (State or other jurisdiction of incorporation or organization)		Kansas (State or other jurisdiction of incorporation or organization)
1311 (Primary Standard Industrial Classification Code Number)		1311 (Primary Standard Industrial Classification Code Number)
06-6554331 (I.R.S. Employer Identification No.)		48-1200438 (I.R.S. Employer Identification No.)
221 West Sixth Street, 1st Floor Austin, Texas 78701 (800) 852-1422 (Address, including zip code, and telephone number, including area code, of co-registrant's Principal Executive Offices)		250 N. Water, Suite 300 Wichita, Kansas 67202 (316) 267-3241 (Address, including zip code, and telephone number, including area code, of co-registrant's Principal Executive Offices)
Mike J. Ulrich The Bank of New York Trust Company, N.A., Trustee Global Corporate Trust 221 West Sixth Street, 1st Floor Austin, Texas 78701 (800) 852-1422 (Name, address, including zip code, and telephone number, including area code, of agent for service)		David L. Murfin 250 N. Water, Suite 300 Wichita, Kansas 67202 (316) 267-3241 (Name, address, including zip code, and telephone number, including area code, of agent for service)

	Per Trust Unit	Total
Initial public offering price	$	$
Underwriting discounts and commissions(1)	$	$
Proceeds, before expenses, to MV Partners	$	$

		The underlying properties
		Proved Reserves as of June 30, 2006 (MMBoe)	Gross Acres	Net Acres
Northwest Kansas Area		8.2	11,885	11,840
El Dorado Area		6.1	15,405	15,393
Other		4.4	20,350	16,649

	Total	18.7	47,640	43,882

			Year ended December 31,									Nine months ended September 30
			2003			2004			2005			2005			2006
			(in thousands)
Revenues:
	Oil sales		$	34,610		$	44,364		$	57,353		$	41,971		$	50,061
	Natural gas sales			562			571			609			373			432
	Natural gas liquid sales			247			294			312			220			247
	Hedge and other derivative activity			(7,383	)		(14,403	)		(22,319	)		(16,825	)		(15,459	)

		Total		28,036			30,826			35,955			25,739			35,281

Direct operating expenses:
	Lease operating expenses			10,156			10,430			11,307			8,440			8,702
	Lease maintenance			1,334			1,454			1,916			1,385			1,598
	Lease overhead			2,047			2,015			2,068			1,533			1,655
	Production and property tax			1,322			1,389			1,867			1,404			2,794

		Total		14,859			15,288			17,158			12,762			14,749

Excess of revenues over direct operating expenses			$	13,177		$	15,538		$	18,797		$	12,977		$	20,532

	Year ended December 31,						Nine months ended September 30,
	2003		2004		2005		2005		2006
	(in thousands)
Excess of revenues over direct operating expenses	$	13,177	$	15,538	$	18,797	$	12,977	$	20,532
Hedge and other derivative activity		7,383		14,403		22,319		16,825		15,459

Excess of revenues over direct operating expenses excluding hedge and other derivative activity	$	20,560	$	29,941	$	41,116	$	29,802	$	35,991

*Copies to:*
Thomas P. Mason Vinson & Elkins L.L.P. 1001 Fannin Street, Suite 2300 Houston, Texas 77002-6760 (713) 758-2222		R. Joel Swanson Baker Botts L.L.P. One Shell Plaza 910 Louisiana, Suite 3200 Houston, Texas 77002 (713) 229-1234

Trust units offered by MV Partners		7,500,000
Trust units outstanding		11,500,000
Use of proceeds		MV Partners is offering all of the trust units to be sold in this offering and MV Partners will receive all proceeds from the offering, other than the 1,125,000 trust units being offered by MV Energy and VAP-I pursuant to the underwriters' option to purchase additional trust units and the proceeds derived therefrom. MV Partners will use the net proceeds from this offering to repay existing indebtedness, and to repurchase a portion of the outstanding equity interests of VAP-I, to make a cash distribution to the members of MV Partners or any combination of the foregoing. See "Use of Proceeds."
Proposed NYSE symbol		MVO
Quarterly cash distributions		Actual cash distributions to the trust unitholders will depend upon the quantity of oil, natural gas and natural gas liquids produced from the underlying properties, the prices received for oil, natural gas and natural gas liquid production and other factors. 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 your original investment. Oil, natural gas and natural gas liquid production from proved reserves attributable to the underlying properties is expected to decline over the term of the trust. See "Risk Factors."
		It is expected that quarterly cash distributions during the term of the trust, other than the first quarterly cash distribution, 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). The first distribution from the trust to the trust unitholders will be made on or about February 23, 2007 to trust unitholders owning trust units on February 15, 2007. The first distribution is likely to be larger than subsequent distributions because it will reflect proceeds from more than one calendar quarter of production.
Net profits interest		The net profits interest will be conveyed to the trust out of MV Partners' interests in the properties comprising the underlying properties. The net profits interest will entitle the trust to receive 80% of the net proceeds during the term of the trust from the sale of production of oil, natural gas and natural gas liquids attributable to MV Partners' interests in the properties comprising the underlying properties.

Termination of the trust		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), and the trust will soon thereafter wind up its affairs and terminate.
Net proceeds		The conveyance creating the net profits interest entitles the trust to receive an amount of cash for each quarter equal to 80% of the net proceeds from the sale of oil, natural gas and natural gas liquid production from the underlying properties net of all payments made under existing hedge contracts. In general, "gross proceeds" means the sales price received by MV Partners from sales of oil, natural gas and natural gas liquids produced during a quarter attributable to the underlying properties net of all payments made by MV Partners to hedge contract counterparties upon monthly settlements of the hedge contracts, while "net proceeds" equals the gross proceeds, less all lease operating expenses, maintenance expenses, lease overhead and capital expenses (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. In addition, the trust will be entitled to receive 80% of all amounts payable to MV Partners from hedge contract counterparties upon monthly settlements of the hedge contracts. For a more detailed description of the determination of "net proceeds," see "Computation of Net Proceeds."
Administrative services fee payable to MV Partners		MV Partners will be entitled to receive an annual administrative services fee, payable quarterly, during the term of the trust, for providing accounting, bookkeeping and informational services relating to the net profits interest. The annual fee will total $60,000 in 2006 and will increase by 4% each year beginning in January 2007. A more detailed description of the administrative services fee is set forth under the caption "The Trust—Administrative Services Fee."

Reserves		Based on the reserve report, the net profits interest would entitle the trust to receive net proceeds from the sale of production of approximately 11.5 MMBoe of proved reserves attributable to the underlying properties 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, as of June 30, 2006, approximately 9.8 MMBoe were classified as proved developed producing reserves and approximately 1.7 MMBoe were classified as proved developed non-producing and proved undeveloped.
Summary of income tax consequences		Trust unitholders will be taxed directly on the income from assets of the trust. The net profits interest should be treated as a debt instrument for federal income tax purposes, and a trust unitholder in that event will be required to include in such trust unitholder's income its share of the interest income on such debt instrument as it accrues in accordance with the rules applicable to contingent payment debt instruments contained in the Internal Revenue Code of 1986, as amended and the corresponding regulations, as well as such trust unitholder's share of any income on the trust's hedges. If the net profits interest is not treated as a debt instrument, then a trust unitholder would be allowed to recoup its basis in the net profits interest on a schedule that is in proportion to production from the net profits interest and that is more favorable to a trust unitholder than the schedule on which basis will be recovered if the net profits interest is treated as a debt instrument for federal income tax purposes. However, the deductions that would be allowed to an individual trust unitholder in that event may be itemized deductions, the deductibility of which would be subject to limitations that may or may not apply depending upon the trust unitholder's circumstances. See "Federal Income Tax Consequences."

				Quarter Ending
				March 31, 2007			June 30, 2007			September 30, 2007			December 31, 2007
				(dollars in thousands, except per Bbl, Mcf and trust unit amounts)
Underlying Properties sales volumes:
	Oil (MBbls)				270.4			267.4			281.3			284.9
	Natural gas (MMcf)				34.3			33.3			32.4			31.5
	Natural gas liquids (MBbls)				2.2			2.2			2.1			2.1
Assumed sales price:
	Oil (per Bbl)			$	58.74		$	58.74		$	58.74		$	58.74
	Natural gas (per Mcf)			$	6.85		$	6.85		$	6.85		$	6.85
	Natural gas liquids (per Bbl)			$	46.84		$	46.84		$	46.84		$	46.84
Calculation of net proceeds:
	Gross proceeds:
		Oil sales		$	15,884		$	15,709		$	16,520		$	16,733
		Natural gas sales			235			228			222			216
		Natural gas liquid sales			105			102			100			98
		Payments made to settle hedge contracts			(227	)		(227	)		(227	)		(227	)

			Total	$	15,997		$	15,812		$	16,615		$	16,820

	Costs:
		Lease operating expenses		$	2,892		$	2,903		$	2,943		$	2,988
		Lease maintenance and development expenses			293			1,018			2,687			1,140
		Lease overhead expenses			559			559			559			560
		Production and property taxes			591			581			643			662

			Total	$	4,335		$	5,061		$	6,832		$	5,350

Net proceeds				$	11,662		$	10,751		$	9,783		$	11,470

Percentage allocable to net profits interest					80	%		80	%		80	%		80	%
Net proceeds to trust from net profits interest				$	9,330		$	8,601		$	7,826		$	9,176

Amounts payable to MV Partners to settle hedge contracts				$	180		$	205		$	123		$	43
Percentage allocable to trust					80	%		80	%		80	%		80	%
Payments to trust from hedge contracts					144			164			98			34

Total cash proceeds to trust					9,474			8,765			7,924			9,210

Trust administrative expenses					166			166			166			166

Projected cash distribution on trust units				$	9,308		$	8,599		$	7,758		$	9,044

Projected cash distribution per trust unit				$	0.81		$	0.75		$	0.67		$	0.79

		Gross	Net
		(acres)
El Dorado Area		15,405	15,393
Northwest Kansas Area		11,885	11,840
Other		20,350	16,649

	Total	47,640	43,882

		Operated Wells		Non-Operated Wells		Total
		Gross	Net	Gross	Net	Gross	Net
Oil		908	888	71	10	979	898
Natural gas		5	4	1	—	6	4

	Total	913	892	72	10	985	902

		Underlying Properties(1)		80% of Underlying Properties(2)		Net Profits Interest(3)
		(in thousands, except Bbl, Mcf and Boe amounts)
Proved Reserves:
	Oil (MBbls)		18,424		11,302		7,318
	Natural gas (MMcf)		1,422		1,006		683
	Natural gas liquids (MBbls)		106		71		48
	Oil equivalents (MBoe)		18,730		11,516		7,463
Future net revenues		$	784,132	$	523,423	$	523,423
Discounted estimated future net revenues(4)		$	358,737	$	278,629	$	278,629
Standardized measure(5)		$	358,737	$	278,629	$	$278,629

		Underlying Properties
		Oil (MBbl)		Natural Gas (MMcf)		Natural Gas Liquids (MBbl)		Oil Equivalents (MBoe)
Balance, December 31, 2002		16,472		2,552		143		16,991
	Revisions, extensions, discoveries and additions	322		(910	)	(26	)	153
	Production	(1,198	)	(116	)	(3	)	(1,219	)

Balance, December 31, 2003		15,596		1,526		114		15,924
	Revisions, extensions, discoveries and additions	1,447		(283	)	(1	)	1,399
	Production	(1,127	)	(104	)	(5	)	(1,147	)

Balance, December 31, 2004		15,915		1,139		108		16,176
	Revisions, extensions, discoveries and additions(1)	3,049		309		5		3,104
	Production	(1,058	)	(89	)	(5	)	(1,076	)

Balance, December 31, 2005		17,906		1,359		109		18,203
	Revisions, extensions, discoveries and additions	1,034		113		0		1,052
	Production	(515	)	(51	)	(3	)	(526	)

Balance, June 30, 2006		18,424		1,422		106		18,730
Proved Developed Reserves:
Balance, December 31, 2002		15,510		1,671		143		15,881
Balance, December 31, 2003		14,913		1,349		114		15,212
Balance, December 31, 2004		15,317		1,139		108		15,577
Balance, December 31, 2005		15,888		1,063		109		16,136
Balance, June 30, 2006		16,460		1,123		106		16,716

Underwriter		Number of Trust Units
Raymond James & Associates, Inc.
A.G. Edwards & Sons, Inc.
RBC Capital Markets Corporation
Oppenheimer & Co. Inc.

	Total	7,500,000

	Per Unit	No Exercise	Full Exercise
Public offering price	$	$	$
Underwriting discounts and commissions
Proceeds, before expenses, to MV Partners
Proceeds, before expenses, to MV Energy and VAP-I


Underlying Properties:
	Report of Independent Registered Public Accounting Firm
	Statements of Historical Revenues and Direct Operating Expenses for Each of the Three Years in the Period Ended December 31, 2005, and for the Nine Months Ended September 30, 2005 and 2006 (unaudited)
	Notes to Statements of Historical Revenue and Direct Operating Expenses
MV Oil Trust:
	Report of Independent Registered Public Accounting Firm
	Statements of Assets and Trust Corpus as of August 11, 2006 and as of September 30, 2006 (unaudited)
	Notes to Statements of Assets and Trust Corpus
	Unaudited Pro Forma Financial Information
		Unaudited Pro Forma Statement of Assets and Trust Corpus as of September 30, 2006
		Unaudited Pro Forma Statements of Distributable Income for the Year Ended December 31, 2005, and for the Nine Months Ended September 30, 2006
		Notes to Unaudited Pro Forma Financial Information

	August 11, 2006		September 30, 2006
			(unaudited)
ASSETS
Cash	$	1,000	$	1,000

TRUST CORPUS
Trust Corpus	$	1,000	$	1,000

		Year ended December 31, 2005			Nine months ended September 30, 2006
Historical results
	Income from the net profits interest and hedge and other derivative activities	$	13,216,968		$	15,479,830
Pro Forma Adjustments
	Less trust general and administative expenses		60,000	(b)		45,000

	Distributable income	$	13,156,968		$	15,434,830

	Distributable income per unit	$	1.14		$	1.34

Oil and gas properties	$	93,804,260
Accumulated depreciation and depletion		(39,770,555	)
Hedge liability		(12,046,381	)

Net property value to be conveyed		41,987,324

Times 80% net profits interest to Trust	$	33,589,859

Year	Notional volume (Bbls)	Fixed price		December 31, 2005 Fair Value			September 30, 2006 Fair value
2007	495,000	$	63.16 - 65.12	$	54,918		$	(1,815,409	)
2008	360,000		60.70		(869,640	)		(2,630,970	)
	45,000		62.99		24,755			(241,965	)

				$	(789,967	)	$	(4,688,344	)

			Year Ended December 31,															Nine Months Ended September 30,
			2001			2002			2003			2004			2005			2005			2006
			(in thousands)
Statements of Earnings Data:
Revenue
	Oil and gas sales		$	24,478		$	24,215		$	28,036		$	30,826		$	35,955		$	25,739		$	35,281
	Interest income			69			20			10			8			207			47			229
	Gain on sale of assets			35			564			—			212			—			—			—

		Total		24,582			24,799			28,046			31,046			36,162			25,786			35,510

Costs and expenses
	Lease operating			15,154			14,528			14,860			15,288			17,158			12,762			14,749
	Depreciation, depletion and amortization			6,053			4,838			5,046			4,252			3,792			2,946			2,397
	General and administrative			291			367			446			448			498			362			453
	Loss on sale of assets			—			—			17			—			89			80			5
	Interest			1,428			891			677			717			1,500			848			4,268

		Total expenses		22,926			20,624			21,046			20,705			23,037			16,998			21,872

Net earnings before accounting change				1,656			4,175			7,000			10,341			13,125			8,788			13,638
	Cumulative effect of change in accounting principle			—			—			90			—			—			—			—

Net earnings			$	1,656		$	4,175		$	7,090		$	10,341		$	13,125		$	8,788		$	13,638

Balance Sheet Data (at end of period):
Oil and gas properties			$	58,407		$	55,114		$	59,250		$	56,857		$	55,284		$	55,669		$	54,034
Total assets				61,993			61,134			65,165			64,437			68,303			78,836			72,943
Working capital				(4,272	)		(473	)		(6,762	)		(6,115	)		(12,185	)		(37,544	)		7,636
Long-term liabilities, excluding current maturities				20,648			25,000			29,484			35,176			91,793			8,279			96,483
Partners' capital (deficit)/Members' deficit				33,655			30,005			23,121			15,697			(48,245	)		9,876			(33,496	)

		Payments Due By Period (in thousands)
		Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-term debt		$	83,000	$	3,000	$	80,000	$	—	$	—
Asset retirement obligation			7,425		—		—		—		7,425
Hedge and other derivative agreements			12,046		2,988		8,642		416		—

	Total	$	102,471	$	5,988	$	88,642	$	416	$	7,425

				General partner/ Class A member						Limited partner/ Class B member
				Capital (deficit)			Accumulated other comprehensive loss			Capital (deficit)			Accumulated other comprehensive loss			Total
Balance at January 1, 2003				$	1,835,689		$	—		$	31,837,957		$	(3,668,759	)	$	30,004,887
Partners' distributions					(1,010,000	)		—			(9,690,000	)		—			(10,700,000	)
Comprehensive income
	Net earnings for the year				723,674			—			6,366,543			—			7,090,217
	Reclassification adjustment for realized losses on swap transactions				—			—			—			7,442,801			7,442,801
	Change in fair value of swap agreements				—			—			—			(10,717,036	)		(10,717,036	)

			Total comprehensive income														3,815,982

Balance at December 31, 2003					1,549,363			—			28,514,500			(6,942,994	)		23,120,869
Partners' distributions					(1,152,500	)		—			(10,497,500	)		—			(11,650,000	)
Comprehensive income
	Net earnings for the year				1,237,661			—			9,102,949			—			10,340,610
	Reclassification adjustment for realized losses on swap transactions				—			—			—			14,402,644			14,402,644
	Change in fair value of swap agreements				—			—			—			(20,517,299	)		(20,517,299	)

			Total comprehensive income														4,225,955

Balance at December 31, 2004					1,634,524			—			27,119,949			(13,057,649	)		15,696,824
Partners' contributions					12,448,422			—			12,448,422			—			24,896,844
Partners' distributions					(26,573,077	)		—			(74,330,468	)		—			(100,903,545	)
Comprehensive income
	Net earnings for the year
		Regular allocation			1,483,836			—			11,641,643			—			13,125,479
		Agreed to reallocation			(420,555	)		—			420,555			—			—
	Unrealized losses on swap transactions
		Reclassification adjustment for realized losses on swap transactions			—			245,977			—			21,224,822			21,470,799
		Change in fair value of swap agreements			—			64,731			—			(22,595,779	)		(22,531,048	)
		Agreed to reallocation of accumulated other comprehensive loss existing at September 30, 2005			—			(915,853	)		—			915,853			—

			Total comprehensive income														12,065,230
Reallocation of partners' capital due to change in ownership percentages effective December 31, 2005					(5,636,525	)		(6,453,804	)		5,636,525			6,453,804			—

Balance at December 31, 2005					(17,063,375	)		(7,058,949	)		(17,063,374	)		(7,058,949	)		(48,244,647	)
Partners' distributions (unaudited)					(1,500,000	)		—			(1,500,000	)		—			(3,000,000	)
Comprehensive income (unaudited)
	Net earnings for the period				6,819,114			—			6,819,114			—			13,638,228
	Reclassification adjustment for realized losses on swap transactions				—			7,133,832			—			7,133,832			14,267,664
	Change in fair value of swap agreements				—			(5,078,421	)		—			(5,078,421	)		(10,156,842	)

			Total comprehensive income														17,749,050

Balance at September 30, 2006 (unaudited)				$	(11,744,261	)	$	(5,003,538	)	$	(11,744,260	)	$	(5,003,538	)	$	(33,495,597	)

Year	Notional volume	Fixed price		Fair value
2005	394,489 Bbls 376,879 Bbls	$	23.82 33.60	$	(7,451,518 (3,299,325	) )
2006	359,565 Bbls		33.60		(2,306,806	)

				$	(13,057,649	)

Year	Notional volume	Fixed price		December 31, 2005 Fair value			September 30, 2006 Fair value
							(unaudited)
2007	495,000 Bbls	$	63.16-65.12	$	54,918		$	(1,815,409	)
2008	360,000 Bbls 45,000 Bbls		60.70 62.99		(869,640 24,755	)		(2,630,970 (241,965	) )

				$	(789,967	)	$	(4,688,344	)

				September 30, 2006
				Historical			Adjustments			Pro Forma

ASSETS
CURRENT ASSETS
	Cash and cash equivalents			$	12,438,387		$	8,981,055	(a)	$	21,419,442
	Accounts receivable—oil and gas sales				5,083,863			—			5,083,863
	Note receivable—related parties				—			3,683,429	(b)		3,683,429
	Prepaid expenses				70,130			—			70,130

			Total current assets		17,592,380			12,664,484			30,256,864
OIL AND GAS PROPERTIES AND EQUIPMENT					93,804,260			(58,313,082)	(c)		35,491,178
	Less accumulated depreciation, depletion and amortization				39,770,555			(24,723,223)	(c)		15,047,332

					54,033,705			(33,589,859)	(c)		20,443,846
OTHER ASSETS
	Deferred offering costs				981,055			(981,055)	(d)		—
	Deferred loan costs, net of accumulated amortization of $112,500 in 2006				336,229			—			336,229

			Total other assets		1,317,284			(981,055	)		336,229

				$	72,943,369		$	(21,906,430	)	$	51,036,939

LIABILITIES AND MEMBERS' DEFICIT
CURRENT LIABILITIES
	Accounts payable
		Trade		$	310,900		$	—		$	310,900
		Related parties			2,987,493			—			2,987,493
		Due to Class A member			531,234			—			531,234
	Settlement payable on oil swap agreements				61,801			—			61,801
	Accrued interest				76,083			—			76,083
	Deferred gain on sale							9,060,505	(d)		9,060,505
	Current maturities of note payable				3,000,000			2,000,000	(e)		5,000,000
	Hedge and other derivative agreements				2,988,371			—			2,988,371

			Total current liabilities		9,955,882			11,060,505			21,016,387
LONG-TERM LIABILITIES, less current maturities
	Note payable				80,000,000			(60,000,000)	(e)		20,000,000
	Deferred gain on sale				—			107,033,065	(d)		107,033,065
	Asset retirement obligation				7,425,074			—			7,425,074
	Hedge and other derivative agreements				9,058,010			—			9,058,010

			Total long-term liabilities		96,483,084			47,033,065			143,516,149
MEMBERS' DEFICIT
	Class A member
		Capital account			(11,744,261	)		(40,000,000)	(f)		(51,744,261	)
		Accumulated other comprehensive loss			(5,003,538	)		—			(5,003,538	)
	Class B member
		Capital account			(11,744,260	)		(40,000,000)	(g)		(51,744,260	)
		Accumulated other comprehensive loss			(5,003,538	)		—			(5,003,538	)

					(33,495,597	)		(80,000,000	)		(113,495,597	)

				$	72,943,369		$	(21,906,430	)	$	51,036,939

		September 30, 2006
(a)	Gross cash proceeds from the sale of the trust units	$	150,000,000
	Cash down payment on related party notes		8,000,000
	Partial repayment of outstanding borrowing on revolving credit facility		(58,000,000	)
	Payment of estimated remaining transaction fees and costs from the sale of trust units		(11,018,945	)
	Distribution to members		(80,000,000	)

		$	8,981,055

(b)	Receivable from related party for sale of 34.8% of trust units at historical value	$	11,683,429
	Cash down payment on receivable	$	8,000,000

	Remaining receivable from related party for sale of 34.8% of trust units	$	3,683,429

(c)	Reduction in property due to conveyance of net profits interest	$	(58,313,082	)
	Reduction of associated accumulated depreciation, depletion, and amortization		24,723,223

		$	(33,589,859	)

	Net oil and gas properties and equipment	$	54,033,705
	Hedge and other derivative agreements		(12,046,381	)

			41,987,324
	80% Net profits interest conveyance	$	33,589,859

(d)	Deferred gain on sale of net profits interest is calculated as follows:
	Gross cash proceeds from the sale of the trust units	$	150,000,000
	Less: Net book value of conveyed net profits interest		(21,906,430	)
	Deferred transaction fees and costs incurred as of September 30, 2006		(981,055	)
	Estimated remaining transaction fees and costs from the sale of trust units		(11,018,945	)

	Deferred gain on sale	$	116,093,570

	Current portion of deferred gain	$	9,060,505
	Long-term portion of deferred gain	$	107,033,065
(e)	To adjust current portion of long-term debt for new credit facility	$	2,000,000
	To adjust long-term portion of debt for new credit facility		(60,000,000	)

	Partial repayment of outstanding borrowing on revolving credit facility	$	(58,000,000	)

(f)	To record distribution of remaining cash to Class A member	$	(40,000,000	)

(g)	To record distribution of remaining cash to Class B member	$	(40,000,000	)

		Year ended December 31, 2005			Nine months ended September 30, 2006
(h)	Decrease in oil and gas sales attributable to net profits interest	$	(28,763,933	)	$	(28,224,822	)

(i)	To record amortization of gain on sale of trust units over the life of the trust	$	8,602,002		$	6,293,240

(j)	Decrease in lease operating expenses attributable to the net profits interest	$	(13,726,396	)	$	(11,799,571	)

(k)	Reduce depreciation on assets sold to Trust	$	(2,403,770	)	$	(1,554,151	)

(l)	To reduce interest expense due to reduction of debt	$	(1,436,311	)	$	(2,688,523	)

AUSTIN OFFICE:	MAIN OFFICE:	HOUSTON OFFICE:
9601 AMBERGLEN BLVD., SUITE 117 AUSTIN, TEXAS 78729 (512) 249-7000 FAX (512) 233-2618	306 WEST 7^TH STREET, SUITE 302 FORT WORTH, TEXAS 76102-4987 (817) 336-2461 FAX (817) 877-3728	1000 LOUISIANA, SUITE 625 HOUSTON, TEXAS 77002-5008 (713) 651-9944 FAX (713) 651-9980

			Proved Developed Producing		Proved Developed Non-Producing	Proved Undeveloped	Total Proved
Net Reserves
	Oil	- MBBL	16,259.0		200.6	1,964.8	18,424.3
	Gas	- MMCF	1,083.5		39.8	298.3	1,421.6
	NGL	- MBBL	106.1		0.0	0.0	106.1
Revenue
	Oil	- M$	1,149,183.0		14,177.4	138,871.5	1,302,231.9
	Gas	- M$	5,362.6		236.0	1,585.1	7,183.8
	NGL	- M$	6,012.9		0.0	0.0	6,012.9
	Hedge	- M$	(35,816.9	)	0.0	0.0	(35,816.9	)
Severance Taxes		- M$	5,959.3		543.7	6,010.4	12,513.4
Ad Valorem Taxes		- M$	28,863.6		360.3	3,511.4	32,735.4
Operating Expenses		- M$	324,398.7		1,982.1	17,405.4	343,786.2
Workover Expenses		- M$	22,040.8		0.0	0.0	22,040.8
COPAS		- M$	63,196.1		169.8	4,189.4	67,555.2
Investments		- M$	0.0		1,070.2	15,778.5	16,848.7
Net Operating Income (BFIT)		- M$	680,283.2		10,287.3	93,561.6	784,131.9
	Discounted @ 10%	- M$	302,813.0		4,797.6	51,126.2	358,736.8

Year	SEC Hedge Gain/(Loss), M$
2006	(4,578.8	)
2007	(8,551.1	)
2008	(11,794.3	)
2009	(5,215.7	)
2010	(5,677.0	)

Exhibit Number		Description
1.1†	—	Form of Underwriting Agreement.
3.1†	—	Articles of Organization of MV Partners, LLC.
3.2†	—	First Amended and Restated Operating Agreement of MV Partners, LLC.
3.3†	—	Certificate of Trust of MV Oil Trust.
3.4†	—	Trust Agreement dated August 3, 2006 among MV Partners and JPMorgan Chase Bank, N.A. and Wilmington Trust Company.
3.5†	—	Form of Amended and Restated Trust Agreement among MV Partners and The Bank of New York Trust Company, N.A. (formerly JPMorgan Chase Bank, N.A.) and Wilmington Trust Company.
3.6†	—	Form of First Amendment to First Amended and Restated Operating Agreement of MV Partners, LLC
5.1†	—	Opinion of Dorsey & Whitney (Delaware) LLP relating to the validity of the trust units.
8.1†	—	Opinion of Vinson & Elkins L.L.P. relating to tax matters.
10.1†	—	Credit Agreement dated as of December 21, 2005 among MV Partners, LP (now MV Partners LLC), as borrower, Bank of America, N.A. and the other parties named therein.
10.2†	—	First Amendment to Credit Agreement dated April 28, 2006 by and among MV Partners, LP (now MV Partners, LLC), as borrower, Bank of America, N.A. and the other parties named therein.
10.3†	—	Second Amendment to Credit Agreement dated September 7, 2006 by and among MV Partners, LLC, as borrower, Bank of America, N.A. and the other parties named therein.
10.4†	—	Form of Term Net Profits Interest Conveyance.
10.5†	—	Form of Administrative Services Agreement.
10.6†	—	Form of Registration Rights Agreement.
10.7†	—	Form of Assignment of Hedge Proceeds.
10.8†	—	Form of Credit Agreement among MV Partners, LLC, as borrower, MV Energy, LLC, and VAP-I, LLC, as guarantors, Bank of America, N.A., as administrative agent, and the other lenders party thereto.
23.1	—	Consent of Grant Thornton LLP.
23.2†	—	Consent of Dorsey & Whitney (Delaware) LLP (contained in Exhibit 5.1).
23.3†	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1).
23.4†	—	Consent of Cawley, Gillespie & Associates, Inc.
24.1†	—	Power of Attorney.

Signature	Title	Date

/s/ DAVID L. MURFIN David L. Murfin	(Co-Principal Executive Officer)	December 18, 2006
/s/ J. MICHAEL VESS J. Michael Vess	(Co-Principal Executive Officer)	December 18, 2006
/s/ RICHARD J. KOLL Richard J. Koll	(Principal Accounting and Financial Officer)	December 18, 2006

MV Oil Trust

MV Partners, LLC

MV Energy, LLC,
its Manager

Murfin, Inc.,
Member

/s/ DAVID L. MURFIN

Name: David L. Murfin
Title: Chairman and Chief Executive Officer