Exhibit 99.1



Cawley,
Gillespie & Associates, Inc.



petroleum
consultants



|13640 BRIARWICK DRIVE, SUITE 100 | 306 WEST SEVENTH STREET, SUITE 302 | 1000 LOUISIANA STREET, SUITE 1900
|-------------------------------- | ---------------------------------- | ---------------------------------
|AUSTIN, TEXAS 78729-1707         | FORT WORTH, TEXAS 76102-4987       | HOUSTON, TEXAS 77002-5008        
|512-249-7000                     | 817- 336-2461                      | 713-651-9944                     
|                                 | www.cgaus.com                      |                                  



February 4, 2022



Bank of New York Mellon Trust Company, N.A. as



Trustee of MV Oil Trust

Attn: Elaina C. Rodgers
601 Travis Street, Floor 16
Houston, Texas 77002



|Re: | Evaluation Summary                                                                                                                    |  |                                                                                                                                             
|--- | ------------------------------------------------------------------------------------------------------------------------------------- |  | --------------------------------------------------------------------------------------------------------------------------------------------
|    | MV
    Oil Trust Net Profits Interests
    Total Proved Reserves
    Certain Oil and Gas Assets — KS & CO
    As of December 31, 2021 |  | Pursuant
    to the Guidelines of the
    Securities and Exchange Commission for
    Reporting Corporate Reserves and
    Future Net Revenue



Gentlemen:



As requested, this report was
prepared on February 4, 2022 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 Company’s
reserves, which are located in certain oil and gas properties in Kansas and Colorado. This evaluation, effective December 31, 2021,
was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities
and Exchange Commission (SEC). A composite summary of the proved reserves is presented below:





|                                        |  |       |  | Proved
    Developed Producing |           |  | Proved
    Developed Non-Producing |   |                                                      | Proved
    Undeveloped |  |   | Total
    Proved | 
|--------------------------------------- |  | ----- |  | ------------------------------ | --------- |  | ---------------------------------- | - | ---------------------------------------------------- | ---------------------- |  | - | ---------------- | 
|Net Reserves                            |  |       |  |                                |           |  |                                    |   |                                                      |                        |  |   |                  | 
|Oil                                     |  | -MBBL |  |                                | 2,309.9   |  |                                    |   | 16.1                                                 |                        |  |   | 108.3            | 
|Gas                                     |  | -MMCF |  |                                | 108.2     |  |                                    |   | 0.0                                                  |                        |  |   | 0.0              | 
|NGL                                     |  | -MBBL |  |                                | 0.4       |  |                                    |   | 0.0                                                  |                        |  |   | 0.0              | 
|Revenue                                 |  |       |  |                                |           |  |                                    |   |                                                      |                        |  |   |                  | 
|Oil                                     |  | -M$   |  | $                              | 143,354.4 |  |                                    | $ | 1,
                                            001.9 |                        |  | $ | 6,719.3          | 
|Gas                                     |  | -M$   |  |                                | 315.2     |  |                                    |   | 0.0                                                  |                        |  |   | 0.0              | 
|NGL                                     |  | -M$   |  |                                | 8.5       |  |                                    |   | 0.0                                                  |                        |  |   | 0.0              | 
|Severance Taxes                         |  | -M$   |  |                                | 873.9     |  |                                    |   | 45.7                                                 |                        |  |   | 249.4            | 
|Ad Valorem Taxes                        |  | -M$   |  |                                | 3,335.7   |  |                                    |   | 54.3                                                 |                        |  |   | 350.4            | 
|Operating Expenses                      |  | -M$   |  |                                | 75,265.7  |  |                                    |   | 39.6                                                 |                        |  |   | 1,082.7          | 
|Future Development Costs                |  | -M$   |  |                                | 0.0       |  |                                    |   | 465.0                                                |                        |  |   | 1,338.1          | 
|80% NPI Net Cash Flow (BFIT)            |  | -M$   |  | $                              | 51,362.2  |  |                                    | $ | 317.8                                                |                        |  | $ | 2,958.9          | 
|80% NPI Disc. @ 10% (Present
    Worth) |  | -M$   |  | $                              | 42,688.0  |  |                                    | $ | 228.8                                                |                        |  | $ | 2,345.2          | 





1









Future revenue was calculated prior to
deducting state production taxes and ad valorem taxes; however, future net cash flow was calculated after deducting these taxes,
future development costs, and operating expenses, but before federal income taxes. Future net cash flow has been discounted at
an annual rate of ten (10) percent, in accordance with SEC guidelines, to determine net present worth. Present worth indicates
the time value of money and should not be construed as being fair market value.



The oil reserves include oil and condensate. Oil
and natural gas liquid (“NGL”) volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands
of standard cubic feet (“MCF”) at contract temperature and pressure base. Barrels of oil equivalent (“BOE”) is
expressed as oil and NGL volumes in barrels plus gas volumes in Mcf divided by six (6) to convert to barrels. Our estimates include
proved reserves only. Neither probable or possible reserves, nor interest in acreage beyond the location of proven reserves have been
estimated.



Proved Developed reserves are the summation of
the Proved Developed Producing and Proved Developed Non-Producing reserve estimates. Proved Developed reserves were estimated at 2,326.0
Mbbl oil, 108.2 MMcf gas and 0.4 Mbbl NGLs (or 2,344.4 MBOE). Of the Proved Developed reserves, 2,328.3 MBOE were attributed to producing
zones in existing wells and 16.1 MBOE were attributed to zones in existing wells not producing



Net Profits Calculations



The net profits interests entitle the Trust to
receive 80% of the net proceeds from the sale of hydrocarbon production within the Company 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 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 March 31, 2024. The cash flow tables in this report reflect the
termination date of June 30, 2026.



Hydrocarbon Pricing



The base SEC oil and gas prices calculated for
December 31, 2021 were $66.56/BBL and $3.598/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average
price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period
prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices (EIA) during 2021 and the base gas
price is based upon Henry Hub spot prices (Gas Daily) during 2021.



Oil price differentials were forecast at -$4.50
per BBL for all properties. Gas price and NGL price differentials varied by property. The base price differentials may include local
basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After
these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $62.06/BBL
for oil, $2.914/MMBTU for gas, and $21.23/BBL for NGLs. All economic factors were held constant in accordance with SEC guidelines.





Economic Parameters



Ownership was accepted as furnished and has not
been independently confirmed. Oil and gas price differentials, lease operating expenses (LOE), workover expenses, overhead expenses and
future development costs were calculated and prepared by you and were thoroughly reviewed by us for accuracy and completeness. LOE (column
22) and overhead (COPAS, column 26) were determined at the well level using averages determined from historical lease operating statements.
Workover Expenses (column 25) were applied to cover the annual costs for recurring well work and wellbore abandonment. All economic parameters,
including expenses and future development costs, were held constant (not escalated) throughout the life of these properties.





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 2.0% 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 current rates of $0.144 per BBL and $0.0205 per MCF, respectively.





2







SEC Conformance and Regulations



The reserve classifications and the economic
considerations used herein for the SEC pricing scenario conform to the criteria of the SEC as defined in pages three (3) and
four (4) of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws,
taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State
restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we
aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.



This evaluation includes 20 PUD cases based in
various fields throughout Kansas, which includes a mix of new drills, deepenings, workovers and recompletions. Each of the drilling locations
proposed as part of the Company development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion,
the Company has indicated they have intent to complete this development plan within the next five (5) years. Furthermore, the Company
has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five (5) year
development plan will be fully executed.





Reserve Estimation Methods



The methods employed in estimating reserves are
described in page two (2) of the Appendix. Reserves for proved developed producing wells were estimated using production performance
methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using
a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high
degree of accuracy.



Non-producing reserve estimates, for both developed
and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide
a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for the Company properties,
due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data,
methods and procedures used herein are appropriate for the purpose served by this report.



General Discussion



The estimates and forecasts were based upon interpretations
of data furnished by your office and available from our files. To some extent information from public records has been used to check
and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications.
Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates
represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production
rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the
revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.



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



Cawley, Gillespie & Associates, Inc.
is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided
petroleum consulting services to the oil and gas industry for over 60 years. This evaluation was supervised by W. Todd Brooker,
President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462).
We do not own an interest in the properties or MV Partners, LLC or MV Oil Trust and are not employed on a contingent basis. We have used
all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data
utilized in the preparation of these estimates are available in our office. 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 end December 31, 2021.



| | Yours very truly,
| | -----------------





| |                                                                                                                       | 
| | --------------------------------------------------------------------------------------------------------------------- | 
| | W. Todd Brooker, P.E.
    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) volumetric and
(4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent
of the data available and the characteristics of the reservoirs.





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



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



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



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



Volumetric.   This method
employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required
are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric
method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods.
These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered
is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of
the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of
accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.



Analogy.   This method,
which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration
of theoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells
with similar production profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. The
analogy method may also be applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made
by other methods. Reserve estimates obtained in this manner 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.





4











APPENDIX



Reserve Definitions and Classifications



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



“(22)   Proved
oil and gas reserves.   Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of
geoscience and engineering data, can be estimated with reasonable certainty to be economically 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





“(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.





5









“(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.



“(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.





6









“(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 is permitted, but not required, to disclose probable or possible
reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”



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





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





7