Exhibit 99.1

CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS9601 AMBERGLEN BLVD., SUITE 117
AUSTIN, TEXAS 78729-1106
512-249-7000

306 WEST SEVENTH STREET, SUITE 302
FORT WORTH, TEXAS 76102-4987
817-336-2461
www.cgaus.com

1000 LOUISIANA STREET, SUITE 625
HOUSTON, TEXAS 77002-5008
713-651-9944


February 15, 2012

Bank
of New York Mellon Trust Company, N.A.
  as Trustee of VOC Energy Trust
Attn: Mike Ulrich
919 Congress Avenue
Austin, Texas 78701

Re:

Evaluation Summary VOC Energy Trust Net Profits InterestsTotal Proved Reserves
Certain Properties in Kansas & Texas
As of December 31, 2011

Pursuant to the Guidelines of the
Securities and Exchange Commission for
Reporting Corporate Reserves and
Future Net Revenue


Gentlemen:

As
requested, this report was prepared on February 15, 2012 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 Trust reserves, which are made up of oil and gas properties in Kansas and Texas owned by VOC Brazos Energy
Partners, L.P. and VOC Kansas Energy Partners, LLC ("Companies"). This evaluation utilized an effective date of December 31, 2011, was prepared using constant prices and costs,
and conforms to Item 1202(a)(8) of Regulation S-K and other rules of theSecurities and Exchange Commission(SEC). A composite
summary of the proved reserves is presented below.

Proved
Developed
Producing

Proved
Developed
Non-Producing

Proved
Undeveloped

Total
ProvedNet ReservesOil


- MBBL


7,858.9


303.4


977.1


9,139.4Gas


- MMCF


4,567.5


92.1


590.0


5,249.7RevenueOil

- M$



706,724.4


27,220.3


88,641.9


822,586.4Gas

- M$



22,455.9


692.3


4,433.3


27,581.6Severance Taxes

- M$



16,211.1


998.0


4,381.8


21,590.9Ad Valorem Taxes

- M$



22,956.7


757.7


2,897.3


26,611.7Operating Expenses

- M$



167,896.6


3,832.4


4,340.0


176,068.9Workover Expenses

- M$



10,028.8


347.8


0.0


10,376.6COPAS

- M$



22,666.9


243.2


114.5


23,024.6Investments

- M$



0.0


1,809.4


18,159.8


19,969.280% NPI Net Operating Income (BFIT)

- M$



391,536.1


15,939.3


50,545.3


458,020.880% NPI Disc. @ 10%

- M$



220,969.1


9,794.6


27,510.4


258,274.1


Future
revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital costs and operating expenses, but
before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been

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discounted
at an annual rate of ten percent to determine its "present worth". The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the
fair market value of the properties.

The
oil reserves include oil and condensate. Oil 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.

Our
estimates are for proved reserves only and do not include any probable or possible reserves nor have any values been attributed to interest in acreage beyond the location for which
undeveloped reserves have been estimated.

Net Profits Calculations

The net profits interests entitle the Trust to receive 80% of the net proceeds attributable to the Companies' interests from the sale
of production from the 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 January 31, 2030. 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, 2011 were $96.19/bbl and $4.118/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 2011 and the base gas
price is based upon Henry Hub spot prices (EIA) during 2011.

Oil
price differentials were forecast at -$7.10 per BBL for all VOC KEP properties and ranged from -$2.20 to -$5.15 per BBL for the VOC Brazos properties. Gas price differentials varied
by property. The base price differentials may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After
these adjustments, the net realized prices for the SEC price case over the trust life of the proved properties was estimated to be $90.00 per barrel for oil and $5.254 per MCF for gas. All economic
factors were held constant in accordance with SEC guidelines.

Economic Parameters

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

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economic
parameters, including expenses and investments, 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
when a rate of 6 barrels/day per oil 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 percent of revenue, but dropped to 3 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 2% 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 3 and 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 17 proved undeveloped locations based in various fields throughout Kansas and Texas. Each of these drilling locations proposed as part of the Companies'
development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, the Companies have indicated they have every intent to complete this development plan within the
next five years. Furthermore, the Companies have demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five year development plan will
be fully executed.

Reserve Estimation Methods

The methods employed in estimating reserves are described in page 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

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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 50 years. This evaluation was supervised by W. Todd Brooker, Senior Vice 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 Brazos Energy Partners, L.P.,
VOC Kansas Energy Partners, LLC 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,GRAPHIC

GRAPHICW. Todd Brooker, P.E.
Senior Vice President CAWLEY, GILLESPIE & ASSOCIATES, INC.Texas Registered Engineering Firm (F-693)


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APPENDIX    Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1)production
performance, (2)material balance, (3)volumetricand
(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 andmaybe 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

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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 applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve
estimates obtained by this method 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.

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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.

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"(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

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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 ispermitted, 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)."

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