Exhibit 99.2

February 24, 2012

Alta Mesa Holdings, LP

15021 Katy Freeway, Suite 400

Houston, Texas 77094

Attention: Mr. Michael E. Ellis

Gentlemen:

As requested for the purpose of annual reporting of reserves under SEC parameters, we have estimated the Proved Reserves and projected the future net revenues for the interests owned by Alta Mesa Holdings, LP (AMH) in certain oil and gas properties located in Florida, Louisiana, Oklahoma and Texas representing approximately 87.5 percent of the proved value of all of the AMH properties. Proved Reserves are sub-categorized as Proved Developed Producing (PDP), Proved Developed Nonproducing (PDNP) and Proved Undeveloped (PUD). The results of our estimates as of December 31, 2011 using SEC pricing parameters without future changes which are discussed later herein are shown below:

Proved Reserves included herein conform to the definition as set forth in the Securities and Exchange Commission Regulation S-X Part 210.4-10 (a) as revised and adopted effective January 1, 2011. The future net revenues are those revenues attributable to AMH’s interests in the underlying properties less appropriate royalties, net profits interests, severance and ad-valorem taxes, operating costs and future capital expenditures. The discounted future net revenue is based on a discount rate of 10 percent per annum. The forecasts assume that no changes in the current economic conditions, sales demand or costs will occur in the future. Estimates of future net revenues and discounted future net revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves. The definition of Proved Reserves is included in 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 are not aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

In general, PDP reserves were estimated for each producing property based on extrapolation of the historical producing trend, material balance calculations, analogy to comparable properties, or volumetric analysis of the producing reservoir. Other methods were used in some cases where, in our opinion, characteristics of the data indicated that such other methods were more appropriate. Performance methods were preferred unless the data demonstrated that their use as the basis for the reserve estimate was inappropriate. PDNP and PUD reserves were estimated primarily by volumetric analysis or analogy with future producing rates and decline trends based upon analogy to offset production experienced in each field. Reserve estimates made utilizing volumetric calculations and analogies are less certain than reserve estimates based on well performance obtained over a period of time during which a substantial portion of the wells ultimate recovery were produced. Capital cost requirements for PDNP and PUD reserves were provided by AMH as were the estimated start dates when not controlled by production from a previous completion. We consider the assumptions, data, methods and procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves and future net revenues herein.

AMH has assured us of their intent and ability to proceed with the development activities included in this report including but not limited to those operations scheduled within the next five years, and that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans. Furthermore, AMH has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this development plan will be fully executed.

Base product prices were determined based on the 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 December 31, 2011. The oil price of $96.19 per barrel is based on the West Texas Intermediate (WTI), Cushing, Oklahoma spot prices. The natural gas price of $4.118 per MMBtu is based on the Henry Hub gas daily prices. Price differentials, transportation, deductions and Btu content were applied as appropriate to adjust these base prices of oil and gas to the specific field market situation. NGL prices were based on the historical relationship between the actual prices received at each respective field and the corresponding WTI benchmark prices.

Forecasted operating costs were based on the average of the actual monthly costs for 2011 as provided by AMH. Operating and capital costs were held constant throughout the life of the projections.

Where appropriate surface and well equipment salvage values and well plugging and field abandonment costs as provided by AMH have been considered in the revenue projections and are included herein as “Other” costs. Where abandonment costs and salvage are not attributable to specific wells, they are allocated to the reserve categories on the basis of net present value and applied at the end of the life of the respective properties.

We have not made any field examinations of the properties nor have we considered potential environmental liabilities which may exist as such analyses were not within the scope of our review. No consideration of state or federal income tax consequences to the owners has been made, nor have indirect costs such as general and administrative overhead been included. We have not reviewed information concerning gas production imbalances, if any, and have made no attempt to evaluate or account for any present or potential future imbalances. Gas volumes shown in summary projections are aggregates of the individual property projections at the official temperature and pressure bases of the areas in which the gas reserves are located, and therefore, may not be stated at a uniform pressure base.

In conducting these analyses, production histories, accounting and cost data, and other financial, operating, engineering, geological and geophysical data supplied by AMH were reviewed. To a lesser extent, nonconfidential data existing in the T. J. Smith & Company, Inc. files and data obtained from commercial services and public sources were also used. We relied upon AMH’s representation of the ownership interests; no independent verifications of these interests were made by T. J. Smith & Company, Inc.

Recovery of reserves, including Proved Reserves, is not without risk, and it should be recognized that any reserve estimate or forecast of production is inherently uncertain and is a function of engineering and geological interpretation and judgment. Such estimates should, therefore, be utilized with the understanding that subsequent production information, technical data, governmental policies, and market conditions different from those present at the time of the evaluation may justify revisions which could increase or decrease the original estimates of reserves or the forecasted production. Actual future prices may vary significantly from the prices utilized herein, and those reserve estimates that are based upon the estimated economic limit may differ significantly from the estimated quantities presented in this report.

Neither T. J. Smith & Company, Inc. nor any of its employees has any interest in AMH, in related entities, or in the subject properties. We are independent with respect to AMH as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. Neither the employment to make this review nor the compensation is contingent on our estimates of reserves and future income for the subject properties.