Exhibit 99.1

CAWLEY, GILLESPIE & ASSOCIATES, INC.PETROLEUM CONSULTANTS9601 AMBERGLEN BLVD., SUITE 117 AUSTIN, TEXAS 78729-1106
512-249-7000
FAX 512-233-2618

306 WEST SEVENTH STREET, SUITE 302
FORT WORTH, TEXAS 76102-4987
817-336-2461
FAX 817-877-3728
www.cgaus.com

1000 LOUISIANA STREET, SUITE 625
HOUSTON, TEXAS 77002-5008
713-651-9944
FAX 713-651-9980


February 15, 2010

Bank
of New York Mellon Trust Company, N.A.
    as Trustee of MV Oil Trust
Attn: Mike Ulrich
919 Congress Avenue
Austin, Texas 78701

Re:

Evaluation Summary MV Oil Trust Net Profits InterestsTotal Proved Reserves
Certain Oil and Gas AssetsKS & CO
As of December 31, 2009

Pursuant to the Rules and Guidelines of the
Securities and Exchange Commission for
Reporting Corporate Reserves and
Future Net Revenue


Gentlemen:

As
requested, this report was prepared on February 15, 2010 for MV Oil Trust ("Trust") for the purpose of submitting our estimates of total proved reserves and forecasts of
economics attributable to the Trust term net profits interests. We evaluated 100% of the Trust reserves, which are made up of oil and gas properties in Kansas and Colorado owned by MV
Partners, LLC ("Company"). This evaluation utilized an effective date of December 31, 2009, and was prepared using constant prices and costs and conforms to the rules and guidelines of
theSecurities and Exchange Commission(SEC). A composite summary of the proved reserves is presented below.

Proved
Developed
Producing

Proved
Developed
Non-Producing

Proved
Undeveloped

Total
ProvedNet ReservesOil

- MBBL


9,153.3


92.7


1,607.8


10,854.0Gas

- MMCF


590.0


137.3


0.0


727.3NGL

- MBBL


39.0


0.0


0.0


39.0RevenueOil

- M$


494,003.6


5,013.8


86,706.4


585,723.8Gas

- M$


2,163.1


387.9


0.0


2,551.1NGL

- M$


1,319.2


0.0


0.0


1,319.2Severance Taxes

- M$


2,988.4


244.1


3,824.1


7,056.6Ad Valorem Taxes

- M$


14,885.0


157.0


2,594.1


17,636.1Operating Expenses

- M$


169,350.3


1,379.0


16,568.0


187,297.2Workover Expenses

- M$


12,767.8


0.0


0.0


12,767.8COPAS

- M$


34,191.4


148.2


1,769.8


36,109.3Investments

- M$


0.0


1,139.0


14,915.0


16,054.080% NPI Net Operating Income (BFIT)

- M$


210,642.5


1,867.5


37,628.4


250,138.480% NPI Disc. @ 10%

- M$


126,060.5


937.6


19,867.8


146,865.9


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.

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Net Profits Calculations

The net profits interests entitle the Trust to receive 80% of the net proceeds attributable to the Company interest from the sale of
production from the underlying properties. The net profits interests will terminate on the later to occur of (1) June 30, 2026, or (2) the time when 14 4 million barrels of
oil equivalent ("MMBOE") have been produced from the underlying properties and sold, and the trust will soon thereafter wind up its affairs and terminate. For this report, it was estimated that the
Trust would terminate June 30, 2026 based on the calculation that 14.4 MMBOE would be 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) by April 30, 2026. The cash flow tables in this report reflect the
termination date of June 30, 2026.

Hydrocarbon Pricing

As requested, oil and gas prices were adjusted to a WTI Cushing oil price of $61.18 per BBL and a Henry Hub natural gas price of $3.833
per MMBTU. As specified by the SEC, these prices are 12-month averages based upon the price on the first day of each month during 2009. Prices were not escalated in accordance with SEC
rules and guidelines.

Oil
price differentials were forecast at -$7.25 per BBL for all properties and were not escalated. Gas and NGL price differentials were forecast on a per property basis as provided by
the Company 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.

Expenses and Taxes

Lease operating expenses, workover expenses, COPAS overhead charges and investments were forecast on a per property basis as furnished
by the Company. Workover expenses were forecast at $92.00 per month per net well for all producing properties. Expenses and investments were held constant in accordance with SEC rules and guidelines.

Severance
tax rates were applied at normal state percentages of oil and gas revenue, except for those Kansas producing properties that are severance tax exempt. Ad valorem taxes of 3.0%
of total revenue were applied to each property as provided by the Company. Oil and gas conservation tax rates were applied to all Kansas properties at current rates of $0.091 per BBL and $0.0129 per
MCF, respectively.

Miscellaneous

An on-site field inspection of the properties hasnotbeen 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 hasnotbeen investigated nor considered. The cost of plugging and the salvage value of equipment at
abandonment havenotbeen included except as noted above.

The
proved reserve classifications used herein conform to the criteria of the Securities and Exchange Commission as defined in pages 2 and 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. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may
impact the recovery of reserves. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report. Numerous uncertainties are inherent in estimating
reserve volumes and values, and the estimates are subject to change as additional information becomes available. It should be realized that

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the
reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

The
methods employed in estimating reserves are described in page 1 of the Appendix. The reserve estimates and forecasts were based upon interpretations of factual data furnished
by the Company. Production data, ownership information, price differentials, expense data and tax details were furnished by the Company, 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 and MV Oil Trust. 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 have used all methods and
procedures that we consider necessary under the circumstances to prepare this report. We do not own an interest in the properties, MV Partners, LLC or MV Oil Trust and are not employed on a
contingent basis. Our work papers and related data are available for inspection and review by authorized, interested parties. We consent to the filing of this report as an exhibit to the Annual Report
on Form 10-K of MV Oil Trust for the year ended December 31, 2009.

Yours very truly,GRAPHICGRAPHICW. Todd Brooker, P.E. Vice PresidentCAWLEY, GILLESPIE & ASSOCIATES, INC.Texas Registered Engineering Firm
(F-693)


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APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1)production
performance,(2)material balance,(3)volumetricand
(4)analogy.Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data
available and the characteristics of the reservoirs.

Basic
information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on
individual properties. Operators are generally required by regulatory authorities to file monthly production reports andmaybe required to measure and
report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and
engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and
reliability of estimates.

A
brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance.This method employs graphical analyses of production data on the premise that all factors which have controlled
the
performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can
usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be
analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of
accuracy with the degree of accuracy increasing as production history accumulates.

Material balance.This method employs the analysis of the relationship of production and pressure performance on the premise that the
reservoir
volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production
relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to
all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of
pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex
calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method
are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric.This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons
in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most
applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or

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no-pressure
depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred
by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be
relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy.This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and
includes
consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve
estimates obtained by this method are generally considered to have a relatively low degree of accuracy.

Much
of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information
becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir
performance.

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APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on
September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

"(22)Proved oil and gas reserves.Proved oil and gas reserves are those quantities of
oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically produciblefrom a given date forward, from known
reservoirs, and under existing economic conditions, operating methods, and government regulationsprior to the time at which contracts providing the right to operate expire, unless
evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have
commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

"(i)
The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions
of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

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

"(iii)
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be
assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

"(iv)
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved
classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed
program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was
based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

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

"(6)Developed oil and gas reserves.Developed oil and gas reserves are reserves of any category that can be
expected to be recovered:

"(i)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

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"(ii)
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

"(31)Undeveloped oil and gas reserves.Undeveloped oil and gas reserves are reserves of any category that are
expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

"(i)
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using
reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

"(ii)
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years,
unless the specific circumstances, justify a longer time.

"(iii)
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other
evidence using reliable technology establishing reasonable certainty.

"(18)Probable reserves.Probable reserves are those additional reserves that are less
certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

"(i)
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When
probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

"(ii)
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the
interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved
area if these areas are in communication with the proved reservoir.

"(iii)
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved
reserves.

"(iv)
See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

"(17)Possible reserves.Possible reserves are those additional reserves that are less
certain to be recovered than probable reserves.

"(i)
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When
probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves
estimates.

"(ii)
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain.
Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

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"(iii)
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable
reserves.

"(iv)
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the
reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

"(v)
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from
proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such
adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in
communication with the proved reservoir.

"(vi)
Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated
gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if
the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable
and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations."

Instruction 4
of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that "a registrant engaged in
oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S-K." This is relevant in that Instruction 2 to paragraph (a)(2)
states: "The registrant ispermitted, but not required,to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through
(a)(2)(vii) of this Item."

"(26)Reserves.Reserves are estimated remaining quantities of oil and gas and related
substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable
expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and
financing required to implement the project.

Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until
those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive
reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from
undiscovered accumulations)."

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