Exhibit 99.2

CAWLEY, GILLESPIE & ASSOCIATES, INC.

March 13, 2012

Mr. Eric Niccum

Jones Energy Holdings, LLC

807 Las Cimas Parkway, Suite 350

Austin, Texas 78746

Dear Mr. Niccum:

As requested, this report was prepared on March 13, 2012 for Jones Energy Holdings, LLC (JEH) for the purpose of submitting our estimates of total proved reserves and forecasts of economics attributable to JEH interests. We evaluated 100% of the Company reserves, which are made up of various oil and gas properties in various states. 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 the Securities and Exchange Commission (SEC).  The results of this evaluation are presented in the accompanying tabulations, with a composite summary of the values presented below:

*  Proved Developed Non-Producing shown above also includes Proved Developed Shut-In properties.

Proved Developed (“PD”) reserves are the summation of the Proved Developed Producing and Proved Developed Non-Producing estimates. Proved Developed reserves were estimated at 2,535.2 Mbbl oil, 110,433.6 MMcf dry gas and 14,020.6 Mbbl NGLs (or 209.8 BCFE). Of the Proved Developed reserves, 184.7 BCFE were attributed to producing zones in existing wells and 25.0 BCFE were attributed to zones in existing wells not producing.

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.

Presentation

The report is divided into a summary section and four reserve category sections.  The summary section includes:  Total Proved (“TP”) and Proved Developed (“PD”).  The four reserve category sections include:  Proved Developed Producing (“PDP”), Proved Developed Non-Producing (“PDNP”), Proved Developed Shut-In (“PDSI”) and Proved Undeveloped (“PUD”).  Within certain reserve category sections are Tables I, Summary Plots and Tables II.  Table I displays composite reserve estimates and economic forecasts for the particular reserve category.  The Summary Plot is a composite rate-time history-forecast curve for the properties summarized in the corresponding Table I.  Following certain Summary Plots are Table II “oneline” summaries that present estimates of ultimate recovery, gross and net reserves, ownership, revenue, expenses, investments, net income and discounted cash flow for the individual properties that make up the corresponding Table I.  The first Table II is sorted by production area and lease name, and the second Table II is sorted by lease name.

For a more detailed explanation of the report layout, please refer to the Table of Contents following this letter.  The data presented in the composite Tables I are explained in page 1 of the Appendix.  The methods employed in estimating reserves are described in page 2 of the Appendix.

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 (Platts) during 2011.

The base prices 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. NGL prices were determined to be approximately 51% of WTI-Cushing oil prices based upon data provided by JEH. After these pricing adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $92.043 per barrel for oil, $3.828 per MCF for gas and $47.260 per barrel for NGL. All economic factors were held constant in accordance with SEC guidelines.

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Economic Parameters

Operating expenses, other deductions and capital expenditures were not escalated.  Lease operating expenses for most wells were forecasted on a per well basis with some utilizing an average expense for the area as provided by JEH.  Gas compression, processing and transportation fees were applied to each property as provided and can be found as Other Deductions (column 27) in the attached tables.  Properties feeding the Cleveland Pipeline System are charged a supplemental $0.44/MCF. The PDP Cleveland Pipeline case is charged a monthly operating cost of $5,326 and the PUD Cleveland Pipeline Case is charged a cost of $0.015 per MCF.

For Texas properties, oil and gas severance tax values were determined by applying normal state tax rates of 4.6% of oil revenue and 7.5% of gas revenue.  Ad Valorem taxes were applied at rates of 2.0% to 3.0% of revenue by property as provided.  The Cleveland horizontal wells qualify for the “High Cost Gas Incentive” state severance tax reduction; therefore, gas severance taxes were applied at 1.0% of gas revenue (15% of standard rate) for 10 years after the start of production and then returned to normal rates of 7.5% for the remaining life of each property as scheduled by JEH.  Other severance tax reduction scenarios were established for certain properties as scheduled by JEH.

For Oklahoma properties, a severance tax of 7.095% of revenue was applied to all vertical producing wells.  A severance tax reduction as outlined in the Oklahoma horizontal well tax incentive guidelines was applied to existing and future horizontal wells.  Reduced severance taxes of 1.095% of revenue were applied to horizontal wells for 48 months if drilled January 1, 2012 or after.  No ad valorem taxes were applied for Oklahoma properties.  Taxes for other states were applied at standard rates.

Reserves and Drilling Locations

CG&A evaluated 642 PDP properties for this report, including the Cleveland Pipeline System, and 114 PDNP properties with start dates and investments as provided.  CG&A evaluated the Cleveland Pipeline System by estimating anticipated throughput volumes and applying current economic and contract parameters.  Revenue for the pipeline system is shown as Other Revenue (column 16) in the attached tables.  Also, 95 PDSI properties were included of which 8 have been identified as plug and abandon (“P&A”) candidates with start dates and abandonment costs ($25,000 per property) as scheduled by JEH.  The remainder of the PDSI properties require further review by JEH for potential upside or confirmation as P&A candidates.

This report also includes 335 PUD locations in Texas and Oklahoma and one (1) Cleveland Pipeline PUD case.  Certain East and West Ellis PUD gas volumes were used to estimate the incremental gas feeding the Cleveland Pipeline PUD case.  The Atoka Lime reservoir has 19 locations, the Cleveland reservoir contains 150 locations plus one Cleveland Pipeline Case, the Granite Wash reservoir contains 17 locations, the Oswego reservoir contains 22 locations and the Woodford reservoir contains 127 locations.  In Texas, a maximum of four (4) horizontal proved locations were assigned to each 640-acre section in most cases to be consistent with the Texas field rules.  JEH has requested drilling permits on five (5) occasions for a fifth horizontal Cleveland location and has not been denied, and has drilled one (1) section with five (5) horizontal Cleveland wells; therefore, some sections were given up to five (5) horizontal proved locations depending on well density and offsetting performance.  In Oklahoma, a maximum of five (5) horizontal proved locations were assigned to each Cleveland 640-acre section based on current field development.

All PUD drills were assumed to be horizontal wells offsetting production from either vertical or horizontal producers (or both).  In the cases where a PUD was offsetting a single vertical producer, reserves were assigned at two times (2X) the vertical well EUR for Cleveland and Atoka Lime locations, assuming geologic and production control were evident.  In the cases where a horizontal PUD Granite Wash location was offsetting a single vertical producer, sufficient nearby Granite Wash vertical and horizontal production

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had to be established in the region as well as geologic control.  In all cases, the type curves used for PUD forecasts were either upgraded or downgraded based on offsetting production in order to hit the target EURs.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein 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.

Each of the commercial drilling locations proposed as part of the Company’s development plan conforms to the proved undeveloped standards as set forth by the SEC.  In our opinion, the Company has indicated they have every intent to complete this development plan within the next five years.  Furthermore, the Company 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 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 Company 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 not been included.

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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 Jones Energy Holdings, LLC 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.

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