Exhibit 99.1



|                                     |  |                                    |  |                                 
|------------------------------------ |  | ---------------------------------- |  | --------------------------------
|CAWLEY, GILLESPIE & ASSOCIATES, INC.
|                                    
|PETROLEUM CONSULTANTS               
|                                     |  |                                   
|9601 AMBERGLEN BLVD., SUITE 117      |  | 306 WEST SEVENTH STREET, SUITE 302 |  | 1000 LOUISIANA STREET, SUITE 625
|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 16, 2012

Mid-Con Energy Partners, LP

2501 N. Harwood, Suite 2410

Dallas, Texas 75201



| |  |  |  |                                       
| |  |  |  | --------------------------------------
| |  |  |  | Re:   Reserve Audit                   
| |  |  |  | Mid-Con Energy Partners, LP Interests 
| |  |  |  | Total Proved Reserves                 
| |  |  |  | As of December 31, 2011               
| |  | 
| |  |  |  | Pursuant to the Guidelines of the     
| |  |  |  | Securities and Exchange Commission for
| |  |  |  | Reporting Corporate Reserves and      
| |  |  |  | Future Net Revenue                    

Gentlemen:

At your request, Cawley, Gillespie & Associates, Inc. (CG&A) has audited the estimates of proved reserves and forecasts of economies attributable to the subject interests of
Mid-Con Energy Partners, LP (MCEP) as of December 31, 2011. This report was prepared for the purposes of describing our audit and for MCEPs use in financial reporting and planning and was completed on February 16, 2012.

We examined 100% of MCEPs reserves, which are made up of oil and gas properties in various fields in Oklahoma and
Colorado. This examination 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 the Securities and Exchange Commission
(SEC). Our examination included all methods and procedures as we considered necessary under the circumstances to render the opinion set forth herein. The estimates as prepared by MCEP are summarized as follows:



|                               |  |         |       |  |        |  |     |      |  |  |             |  |  |  |         | 
|------------------------------ |  | ------- | ----- |  | ------ |  | --- | ---- |  |  | ----------- |  |  |  | ------- | 
|                               |  |         |       |  |        |  |     |      |  |  | Cumulative  | 
|                               |  | Net     |       |  | Net    |  |     |      |  |  | Cash Flow   | 
|                               |  | Oil     |       |  | Gas    |  |     | Net  |  |  | Disc. @ 10% | 
|                               |  | (Mbbls) |       |  | (MMcf) |  |     | MBOE |  |  | (M$)        | 
|                               |  |         |       | 
|Total Proved                   |  |         | 9,936 |  |        |  | 676 |      |  |  | 10,049      |  |  |  | 328,946 | 
|Proved Developed Producing     |  |         | 5,415 |  |        |  | 695 |      |  |  | 5,531       |  |  |  | 189,214 | 
|Proved Developed Non-Producing |  |         | 1,276 |  |        |  | 0   |      |  |  | 1,276       |  |  |  | 55,193  | 
|Proved Developed Behind Pipe   |  |         | 144   |  |        |  | 0   |      |  |  | 144         |  |  |  | 5,157   | 
|Proved Undeveloped             |  |         | 3,101 |  |        |  | -19 |      |  |  | 3,098       |  |  |  | 79,381  | 



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February 16, 2012

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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 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 audit involved proved reserves only and did 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.

Hydrocarbon Pricing

The base SEC oil and gas prices calculated for December 31, 2011 were $96.19/bbl and $4.11/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 and gas prices are
based upon WTI-Cushing and Henry Hub spot prices, respectively, as published by the EIA for January 1, 2010 through December 1, 2011.

The base prices shown above were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or
crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $93.20 per barrel for oil and $7.04 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, gas shrinkage, ad valorem
taxes, severance taxes, lease operating expenses and investments were calculated and prepared by MCEP and were reviewed by us for reasonableness. Lease operating expenses were either determined at the field or individual well level using averages
calculated from historical lease operating statements. All economic parameters, including lease operating expenses and investments, were held constant (not escalated) throughout the life of these properties.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 6 and 7 following this report. The reserves and economics are predicated on
regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. Government policies and market conditions different from those employed in this report may cause (1) the total quantity of
oil or gas to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capital costs to vary from those presented in this report. However, we do not anticipate nor are we aware of any legislative changes or
restrictive regulatory actions that may impact the recovery of reserves.



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Reserve Audit

February 16, 2012

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This evaluation includes 44 proved undeveloped locations, which includes three
(3) locations in the Harker Ranch Field in Colorado and 41 locations in various fields in Oklahoma. Each of these drilling locations proposed as part of MCEPs development plans conforms to the proved undeveloped standards as set forth by
the SEC. In our opinion, MCEP has indicated they have every intent to complete this development plan within the next five years. Furthermore, MCEP has 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 5 following this letter. 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. For certain fields either being waterflooded or prepared for a waterflood, proved undeveloped reserves were based upon
results from either a pilot waterflood (in the field) or an analogous, nearby waterflood deemed to be relevant. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves
for MCEP 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.
Negative gas reserve volumes shown in the attached cash flow tables for the proved undeveloped category reflect a minor loss of reserves associated with conversion of producing wells to water injection.

General Discussion

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 CG&A. 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 not been included.

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.

It should be understood that our audit and the development of our reserves forecasts do not constitute a complete
reserve study of the oil and gas properties of MCEP. In the conduct of our audit,



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we have not independently verified the accuracy and completeness of information and data furnished by MCEP with respect to ownership interests, oil and gas production, historical costs of
operation and developments, product prices, agreements relating to current and future operations and sales of production. Furthermore, if in the course of our examination something came to our attention which brought into question the validity or
sufficiency of any of such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or independently verified such information or data.

Please be advised that, based upon the foregoing, in our opinion the above-described estimates of Mid-Con Energy Partners, LPs
total proved reserves are, in the aggregate, reasonable within the established audit tolerance guidelines of (+ or ) 10%. Also, these estimates have been prepared in accordance with generally accepted petroleum engineering and evaluation
principles as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers and as mandated by the SEC.

CG&A 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 Robert D. Ravnaas, President at CG&A and a State of Texas Licensed Professional Engineer (License #61304). We do not own
an interest in the properties of Mid-Con Energy Partners, LP 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.



Sincerely,CAWLEY, GILLESPIE & ASSOCIATES, INC.LOGO

LOGORobert D. Ravnaas, P.E.President




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Reserve Audit

February 16, 2012

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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 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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Reserve Audit

February 16, 2012

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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.



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(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).