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 78729-1106         | FORT WORTH, TEXAS 76102-4987         | HOUSTON, TEXAS 77002-5008        
|512-249-7000                     | 817- 336-2461                        | 713-651-9944                     
|                                 | www.cgaus.com                        |                                  
|                                 |                                      |                                  
|                                 | February 19, 2024                    |                                  



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



as Trustee of VOC Energy Trust



Attn: Elaina C. Rodgers



601 Travis Street, Floor 16



Houston, Texas 77002





| | Re: | Evaluation Summary                      
| | --- | ----------------------------------------
| |     | VOCET Energy Trust Net Profits Interests
| |     | Total Proved Reserves                   
| |     | As of December 31, 2023                 
| |     |                                         
| |     | Pursuant to the Guidelines of the       
| |     | Securities and Exchange Commission for  
| |     | Reporting Corporate Reserves and        
| |     | Future Net Revenue                      



Dear Trustee:



As
requested, this report was prepared on February 19, 2024 for VOC Energy 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 reserves associated with the Trust, which are made up of various oil and gas properties in Kansas and Texas owned by VOC
Kansas Energy Partners, LLC and VOC Brazos Energy Partners, LP (“Companies”). 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 |  |           | 2,310.4   |  |               |  | 14.5    |             |  |  | 523.6    |  
|Gas                                 |  | - MMCF |  |           | 1,096.8   |  |               |  | 0.0     |             |  |  | 133.5    |  
|NGL                                 |  | - MBBL |  |           | 88.6      |  |               |  | 0.0     |             |  |  | 30.5     |  
|Revenue                             |  |        |  |           |           |  |               |  |         |             |  |  |          |  
|Oil                                 |  | - M$   |  |           | 172,976.2 |  |               |  | 1,068.2 |             |  |  | 40,270.1 |  
|Gas                                 |  | - M$   |  |           | 2,014.1   |  |               |  | 0.0     |             |  |  | 151.8    |  
|NGL                                 |  | - M$   |  |           | 1,802.7   |  |               |  | 0.0     |             |  |  | 620.7    |  
|Severance Taxes                     |  | - M$   |  |           | 4,151.1   |  |               |  | 48.3    |             |  |  | 1,907.8  |  
|Ad Valorem Taxes                    |  | - M$   |  |           | 4,584.6   |  |               |  | 64.1    |             |  |  | 1,443.6  |  
|Operating Expenses                  |  | - M$   |  |           | 80,952.7  |  |               |  | 300.7   |             |  |  | 2,361.3  |  
|Future Development Costs            |  | - M$   |  |           | 237.7     |  |               |  | 186.1   |             |  |  | 36,367.3 |  
|80% NPI Net Cash Flow (BFIT)        |  | - M$   |  |           | 69,493.4  |  |               |  | 375.2   |             |  |  | (829.9   | )
|80% NPI Disc. @ 10% (Present Worth) |  | - M$   |  |           | 53,295.5  |  |               |  | 292.3   |             |  |  | (3,420.0 | )













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. For this report, 80% NPI net cash flowis shown to represent 80% of the future net cash flow, per
the guidelines of the Trust, as described below. 80% NPI 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 2,324.9 Mbbl oil, 1,096.8 MMcf gas and 88.6 Mbbl NGLs (or 2,596.3 MBOE). Of the Proved Developed reserves,
2,581.8 MBOE were attributed to producing zones in existing wells and 14.5 MBOE were attributed to zones in existing wells not producing.



For
a detailed description of the report layout, please refer to the Table of Contents following this letter. The data presented in each
Table I is explained in page one (1) of the Appendix.



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 Companies’
underlying properties. The net profits interests will terminate on the later to occur (1) December 31, 2030, or (2) the
time when 10.6 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 December 31,
2030 based on the calculation that 10.6 MMBOE would be produced from the underlying properties and sold (which amount is the equivalent
of 8.5 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 September 30, 2027. The cash flow tables in this report reflect the termination date of December 31,
2030.



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 Kansas properties. For Texas properties, oil price differentials were applied
at -$1.00 per BBL for the Kurten (Woodbine) Field and Madisonville West Field wells, -$3.25 per BBL for the Sand Flat Field wells, and
-$4.50 per BBL for the Hitts Lake North Field wells. Gas price differentials varied by property as provided. NGL prices were applied
at 26% of the WTI oil price. These 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 over the life
of the proved properties was estimated to be $75.24 per BBL for oil, $1.760 per MCF for gas and $20.34 per 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, and overhead expenses were calculated and prepared by the Companies and reviewed by us for accuracy and completeness.
LOE (column 22) and overhead (COPAS, column 26) shown in the tables provided herein were determined at the well level using averages
determined from historical lease operating statements. Overhead costs include fixed rate administrative overhead for operated properties.
Workover Expenses (column 25) were applied to cover the annual costs for recurring well work and wellbore abandonment. The variable costs
consist of fees for water disposal, gas compression, processing and transportation, and other variable expenses and can be found as Other
Deductions (column 27). All economic parameters were held constant (not escalated) throughout the life of these properties.



Future
development costs for PDNP and PUD properties include recompletion, drilling, and completion costs for both vertical and horizontal wells
as provided by the Companies. For certain producing and undeveloped horizontal wells, a future development cost for conversion to rod
pump is included. All future development costs were held constant (not escalated) throughout the life of these properties.













For
Kansas properties, severance taxes were applied at 4.33 percent of revenue until exemption levels were forecasted to be reached. The
severance tax rate was dropped to zero (0) when a rate of six (6) BBL/day per well was reached, or when gross gas production value
reached $87/day per gas well. Severance taxes were forecasted at 4.6 percent of oil revenue and 7.5 percent of gas and NGL revenue for
properties in Texas. Ad valorem taxes for Kansas properties were applied at 6.0 percent of revenue, but dropped to 2.0 percent as properties
qualified for the tax exemption. Kansas oil and gas conservation taxes were included within the severance tax estimates shown herein.
Ad valorem taxes were applied at 3.29 percent of revenue (after severance taxes) for Texas properties.



Reserve Estimation
Methods



The
methods employed in estimating reserves are described in page two (2) of the Appendix. We evaluated 327 PDP properties for
this report, most with monthly production data typically updated through 10/31/2023, as provided by the Companies. 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 Companies’ 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 11 PUD locations in various fields throughout Kansas and Texas. It should be noted that certain PUD locations do
not reach commerciality as of the Trust termination date, but are still included in this report as they are projected to reach positive
cumulative discounted cash flow at a later date. Each of these drilling locations proposed as part of the Companies’ development
plans conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, the Companies have indicated they have intent
to complete this development plan within the next five (5) years. Furthermore, the Companies have 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, VOC Energy Trust, or the Companies 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.



| | 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).”