EXHIBIT 99.1







March 14, 2023



Mr. Ron Hooper

PermRock Royalty Trust

2911 Turtle Creek Blvd., Suite 850

Dallas, TX 75219



| | Re: | Evaluation Summary                         
| | --- | -------------------------------------------
| |     | PermRock Royalty Trust Net Profits Interest
| |     | Proved Reserves                            
| |     | Various Counties, Texas                    
| |     | As of December 31, 2022                    



Dear Mr. Hooper:



As
requested, we are submitting our estimates of proved reserves and our forecasts of the resulting economics attributable to the above captioned
interests. We completed our evaluation on March 14, 2023.It is our understanding that the proved reserves estimated in this report
constitute 100% of all proved reserves owned by PermRock Royalty Trust. This report has been prepared for use in filings with the Securities
and Exchange Commission. In our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate
for such purpose.



Composite
reserve estimates and economic forecasts are summarized below:





|                            |        |           | Proved    |           |          
|--------------------------- | ------ | --------- | --------- | --------- | ---------
|                            |        | Proved    | Developed | Proved    |          
|                            |        | Developed | Non-      | Un-       |          
|                            |        | Producing | Producing | Developed | Proved   
|Net Reserves                |        |           |           |           |          
|Oil                         | – Mbbl | 1,510.8   | 327.6     | 1,129.0   | 2,967.4  
|Gas                         | – MMcf | 1,433.5   | 684.8     | 622.1     | 2,740.4  
|Revenue                     |        |           |           |           |          
|Oil                         | – M$   | 139,078.5 | 29,936.6  | 103,405.5 | 272,420.5
|Gas                         | – M$   | 11,454.7  | 4,415.3   | 3,709.9   | 19,579.9 
|Severance and               |        |           |           |           |          
|Ad Valorem Taxes            | – M$   | 0.0       | 0.0       | 0.0       | 0.0      
|Operating Expenses          | – M$   | 0.0       | 0.0       | 0.0       | 0.0      
|Investments                 | – M$   | 0.0       | 0.0       | 0.0       | 0.0      
|Net Operating Income (BFIT) | – M$   | 150,533.3 | 34,351.9  | 107,115.4 | 292,000.5
|Discounted @ 10%            | – M$   | 83,791.0  | 14,065.3  | 47,161.9  | 145,018.3









Evaluation Summary

PermRock Royalty Trust Net Profits Interests

As of December 31, 2022

Page 2 of 7



In
accordance with the Securities and Exchange Commission guidelines, the operating income (BFIT) has been discounted at an annual rate of
10% to determine its “present worth”. The discounted value shown above should not be construed to represent an estimate of
the fair market value by Cawley, Gillespie & Associates, Inc.



The
annual average Henry Hub spot market gas price of $6.358 per MMBtu and the annual average WTI Cushing spot oil price of $93.67 per barrel
were used in this report. In accordance with the Securities and Exchange Commission guidelines, these prices are determined as an unweighted
arithmetic average of the first-day-of-the-month price for 12 months prior to the effective date of the evaluation. The oil and gas prices
were held constant and were adjusted to wellhead prices by property based on values supplied by Boaz Energy II, LLC (“Boaz”).
Deductions were applied to the net gas volumes for fuel and shrinkage. The adjusted volume-weighted average product prices over the life
of the properties are $91.82 per barrel of oil and $7.21 per Mcf of gas.



Operating
expenses and capital costs for the underlying properties were supplied by Boaz and reviewed for reasonableness. Severance tax rates were
specified by property based on published state rates, with 50% oil severance tax abatements for 10 years on qualified waterflood projects.
Ad valorem taxes were forecast as 2.48% to 3.5% of net revenue. As per the Securities and Exchange Commission guidelines, neither expenses
nor investments were escalated. The cost of plugging and the salvage value of equipment have not been considered.



All
proved reserve classifications conform to criteria of the Securities and Exchange Commission as set forth in Rules 4-10 of Regulation
S-X and defined in pages 1 and 2 of the Appendix. The proved developed non-producing reserves include those associated with behind-pipe
zones, workovers and proved waterflood projects with current water injection and very minor remaining capital expenditures. The reserves
and economics are predicated on the 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. The reserves were estimated using a combination of the production performance, volumetric and analogy methods, in each case
as we considered to be appropriate and necessary to establish the conclusions set forth herein. The methods employed in estimating reserves
are described in page 3 of the Appendix. 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.









Evaluation Summary

PermRock Royalty Trust Net Profits Interests

As of December 31, 2022

Page 3 of 7





The
reserve estimates were based on interpretations of factual data furnished by Boaz and PermRock Royalty Trust. Ownership interests were
supplied by and were accepted as furnished. To some extent, information from public records has been 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. An on-site inspection of
these properties has not been made nor have the wells been tested by Cawley, Gillespie & Associates, Inc.



Cawley,
Gillespie & Associates, Inc. is independent with respect to PermRock Royalty Trust as provided in the Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers (“SPE Standards”).
Neither Cawley, Gillespie & Associates, Inc. nor any of its employees has any interest in the subject properties. Neither the employment
to make this study nor the compensation is contingent on the results of our work or the future production rates for the subject properties.



Our
work-papers and related data are available for inspection and review by authorized parties.



| | Respectfully submitted,                
| | ---------------------------------------
| |                                        
| | CAWLEY, GILLESPIE & ASSOCIATES, INC.   
| | Texas Registered Engineering Firm F-693













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).”













| | 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 make 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.