Exhibit 99.1



Cawley,
Gillespie & Associates, Inc.



petroleum
consultants



|6500 RIVER PLACE BLVD, BLDG 3, SUITE 200 |  | 306
    WEST SEVENTH STREET, SUITE 302 |  | 1000
    LOUISIANA STREET, SUITE 1900
|---------------------------------------- |  | -------------------------------------- |  | -------------------------------------
|AUSTIN, TEXAS 78730                      |  | FORT WORTH, TEXAS 76102                |  | HOUSTON, TEXAS 77002                 
|512-249-7000                             |  | 817- 336-2461                          |  | 713-651-9944                         
|                                         |  |                                        |  |                                      
|                                         |  | www.cgaus.com                          |  |                                      



March 16, 2024



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

as Trustee of MV
Oil Trust

Attn: Elaina C.
Rodgers

919 Congress Avenue

Austin, Texas 78701



|Re:                                  | Evaluation Summary          |                                            | Pursuant to the
    Guidelines of the
|------------------------------------ | --------------------------- | ------------------------------------------ | -------------------------------------
|MV Oil Trust Net Profits Interests   |                             | Securities and Exchange
    Commission for
|Total Proved Reserves                |                             | Reporting Corporate Reserves
    and      
|Certain Oil and Gas Assets – KS & CO |                             | Future Net Revenue                        
|                                     | As of December
    31, 2023 |                                            |                                      



Ladies and Gentlemen:



As requested, this report was prepared on
March 16, 2024 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 associated with certain oil and gas properties in Kansas and Colorado. This evaluation, effective December 31, 2023,
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    |  |          | Proved        |  |  |             |  |  |        |        
|------------------------ |  |  | -------------------------------------------------- |  | --------- |  | -------- | ------------- |  |  | ----------- |  |  | ------ | -------
|                         |  |  |                                                    |  | Developed |  |          | Developed     |  |  | Proved      |  |  | Total  |        
|                         |  |  |                                                    |  | Producing |  |          | Non-Producing |  |  | Undeveloped |  |  | Proved |        
|Net Reserves             |  |  |                                                    |  |           |  |          |               |  |  |             |  |  |        |        
|Oil                      |  |  | -
                                            MBBL |  |           |  | 1,330.0  |               |  |  | 6.9         |  |  |        | 17.4   
|Gas                      |  |  | -
                                            MMCF |  |           |  | 44.0     |               |  |  | 0.0         |  |  |        | 0.0    
|NGL                      |  |  | -
                                            MBBL |  |           |  | 0.2      |               |  |  | 0.0         |  |  |        | 0.0    
|MBOE                     |  |  | -
                                            MBBL |  |           |  | 1,337.5  |               |  |  | 6.9         |  |  |        | 17.4   
|                         |  |  |                                                    |  |           |  |          |               |  |  |             |  |  |        |        
|Revenue                  |  |  |                                                    |  |           |  |          |               |  |  |             |  |  |        |        
|Oil                      |  |  | -
                                            M$   |  |           |  | 98,045.9 |               |  |  | 511.6       |  |  |        | 1,282.7
|Gas                      |  |  | -
                                            M$   |  |           |  | 105.8    |               |  |  | 0.0         |  |  |        | 0.0    
|NGL                      |  |  | -
                                            M$   |  |           |  | 6.9      |               |  |  | 0.0         |  |  |        | 0.0    
|Severance Taxes          |  |  | -
                                            M$   |  |           |  | 580.4    |               |  |  | 23.1        |  |  |        | 58.0   
|Ad Valorem Taxes         |  |  | -
                                            M$   |  |           |  | 2,300.9  |               |  |  | 30.7        |  |  |        | 77.0   
|Operating Expenses       |  |  | -
                                            M$   |  |           |  | 46,176.9 |               |  |  | 19.2        |  |  |        | 187.0  
|Future Development Costs |  |  | -
                                            M$   |  |           |  | 0.0      |               |  |  | 250.0       |  |  |        | 340.0  
|Future Net Cash Flow     |  |  | -
                                            M$   |  |           |  | 39,280.4 |               |  |  | 150.8       |  |  |        | 496.6  
|Discounted @ 10%         |  |  | -
                                            M$   |  |           |  | 35,199.8 |               |  |  | 123.2       |  |  |        | 427.9  
|(Present
    Worth)      |  |  |                                                    |  |           |  |          |               |  |  |             |  |  |        |        



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 1,336.9 Mbbl oil, 44.0 MMcf gas and 0.2 Mbbl NGLs (or 1,344.4 MBOE). Of the Proved Developed reserves, 1,337.5 MBOE were
attributed to producing zones in existing wells and 6.9 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 February 29, 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 year end 2023 were $78.22/bbl and $2.637/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 market prices during 2023 and the base gas price
is based upon Henry Hub spot market prices during 2023.



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 $73.72/BBL for oil, $2.406/MMBTU for gas, and $31.29/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, gas and NGL 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.



Reserve Estimation Methods



The methods employed in estimating
reserves are described in page two (2) of the Appendix. We evaluated 849 PDP properties for this report, most with monthly production
data typically updated through 10/31/2023, as provided by the Company. Certain PDP properties consist of multiple-well leases. Reserves
for PDP 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 PDNP and PUD 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.



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 four
(4) PUD locations based in various fields throughout Kansas, which includes a mix of new drills, deepenings, workovers and recompletions.
Certain PUD properties consist of multiple development locations. 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.



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, 2023. This report, issued March 16, 2024,
supersedes any prior CGA report for MV Oil Trust with an effective date of December 31, 2023.



| | Yours very truly,                        
| | -----------------------------------------
| |                                          
| |                                          
| | W. Todd Brooker, P.E.                    
| | President                                
| | CAWLEY, GILLESPIE & ASSOCIATES, INC.     
| | Texas Registered Engineering Firm (F-693)













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.













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.



“(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.













“(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).”