Exhibit 99.1







February 18, 2022



|Bank of New York Mellon Trust Company, N.A. as
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|Trustee of VOC Energy Trust                   
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|Attn: Elaina C. Rodgers                       
|601 Travis Street, Floor                      
|Houston, Texas 77002                          
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|Re:                                           
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Dear Trustee:



As requested, this report
was prepared on February 18, 2022 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, 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 |  |                            | 3,016.4   |  |                                |  | 9.9   |                    |  |  | 1,034.5      | 
|Gas                                     |  | -MMCF |  |                            | 1,563.8   |  |                                |  | 0.0   |                    |  |  | 597.3        | 
|NGL                                     |  | -MBBL |  |                            | 56.7      |  |                                |  | 0.0   |                    |  |  | 93.8         | 
|Revenue                                 |  |       |  |                            |           |  |                                |  |       |                    |  |  |              | 
|Oil                                     |  | -M$   |  |                            | 189,899.8 |  |                                |  | 611.5 |                    |  |  | 66,593.2     | 
|Gas                                     |  | -M$   |  |                            | 4,279.0   |  |                                |  | 0.0   |                    |  |  | 1,253.1      | 
|NGL                                     |  | -M$   |  |                            | 1,132.4   |  |                                |  | 0.0   |                    |  |  | 1,872.8      | 
|Severance Taxes                         |  | -M$   |  |                            | 4,847.0   |  |                                |  | 25.8  |                    |  |  | 3,120.2      | 
|Ad Valorem Taxes                        |  | -M$   |  |                            | 5,213.0   |  |                                |  | 34.8  |                    |  |  | 2,260.9      | 
|Operating Expenses                      |  | -M$   |  |                            | 91,670.8  |  |                                |  | 0.0   |                    |  |  | 4,314.8      | 
|Future Development Costs                |  | -M$   |  |                            | 364.9     |  |                                |  | 116.0 |                    |  |  | 30,205.1     | 
|80% NPI Net Cash Flow (BFIT)            |  | -M$   |  |                            | 74,572.4  |  |                                |  | 348.0 |                    |  |  | 23,854.5     | 
|80% NPI Disc. @ 10% (Present
    Worth) |  | -M$   |  |                            | 54,126.6  |  |                                |  | 231.8 |                    |  |  | 13,259.8     | 



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 capital 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 3,026.3 Mbbl oil, 1,563.8 MMcf gas and 56.7 Mbbl NGLs (or 3,343.6 MBOE). Of the Proved Developed reserves, 3,333.7 MBOE were
attributed to producing zones in existing wells and 9.9 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 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 August 31, 2026. 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 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 (Platts Gas Daily) during 2021.



Oil price differentials were
forecast at -$4.50 per BBL for all Kansas properties. For Texas properties, oil price differentials were applied at -$2.00 per BBL for
the Kurten (Woodbine) Field wells and -$3.75 per BBL for the Sand Flat and Hitts Lake North Fields. Oil price differentials for all other
wells in Texas were applied at -$2.00 per BBL. Gas price differentials varied by property as provided. NGL prices were applied at 30%
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 $63.32 per BBL for oil, $2.560 per MCF for gas and $19.97 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 CG&A 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 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.













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 14
commercial PUD locations in various fields throughout Kansas and Texas. 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.



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 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.



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 VOC Energy 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.



| | Yours very truly,                        
| | -----------------------------------------
| |                                          
|
| | W. Todd Brooker, P.E.                    
| | Senior Vice 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.





1







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.
| | ----- | --------------------------------------------------------------------------------------------------------------------------------------------------------------





2







“(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.
| | ----- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------





3







| | “(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).”





4