Exhibit 23.3

February 2, 2010

The Meridian Resource Corporation
1401 Enclave Parkway, Suite 300
Houston, Texas 77077

Attention: Mr. Paul D. Ching

		Re:		Reserves and Future Net Revenues as of December 31, 2009 Using SEC Parameters

Gentlemen:

     At your request, we have estimated the Proved Developed Producing (PDP), Proved Developed Shut-In (PDSI), Proved Developed Nonproducing (PDNP) and Proved Undeveloped (PUD) reserves attributable to the interests owned by The Meridian Resource Corporation (TMR) in various fields located in Louisiana, Oklahoma and Texas. The results of our estimates using prices in effect at year-end 2009 without future changes are shown in the table below as of December 31, 2009 and in Table I which is a one-line summary aggregating all of the properties by field and reserve classification located in the “Tables” section of this report.

		Net Reserves												Future Net Revenue
		Gas				Oil				NGL				Total				Discounted
Category		(MMcf)				(MBbls)				(MBbls)				($M)				@ 10% ($M)
PDP			18,040.4				1,192.4				239.8				74,788.9				62,060.6
PDSI			16.6				0.0				0.0				62.2				53.2
PDNP			14,502.0				1,003.3				135.9				55,839.9				41,263.8
PUD			19,803.1				938.9				257.8				58,472.1				35,576.9
Total Proved			52,362.1				3,134.6				633.5				189,163.1				138,954.6

     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, 2010. The future net revenues are those revenues attributable to TMR’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.

     Economic analyses are presented in the exhibits which show annual projections of production, revenues and costs. Consolidated company total summaries by reserve category are followed by the appropriate projections for each individual field and property. Table II is a one-line summary which includes

all of the individual wells or properties sorted by field and reserve category. Table III is a one-line summary report showing results for each property ranked in descending order of discounted future net revenues for all proved reserve categories.

     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. Capital cost requirements for PDNP and PUD reserves were provided by TMR as were the estimated start dates when not controlled by production from a previous completion.

     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, 2009. The oil price of $61.18 per barrel is based on the West Texas Intermediate (WTI), Cushing, Oklahoma spot prices. The natural gas price of $3.866 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 an 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.

     Capital costs including abandonment costs and development schedules were provided by TMR. Forecasted operating costs were based on the average of the actual monthly costs for 2009 as provided by TMR. Estimated capital expenditures were provided by TMR. 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 TMR 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 TMR 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 TMR’s representation of the ownership interests; no independent verifications of these interests were made by T. J. Smith & Company, Inc.

     Recovery of Proved Reserves is not without risk, and it should be recognized that any reserve estimate or forecast of production is a function of engineering and geological interpretation and judgement. 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 December 31, 2009 prices, 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 TMR, in related entities, or in the subject properties. We are independent with respect to TMR 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.

     The details of our investigations are retained in our files. If you have any questions regarding any of the above, please notify us.

TJS/kl

Enclosures

APPENDIX

SEC Reserve Definitions

The Securities and Exchange Commission (SEC) sets forth standards by which reserves are to be considered as proved for purposes of completing SEC reporting requirements. These standards as defined in Section 4-10(a) of Securities and Exchange Commission Regulation S-X are summarized as follows:

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.

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 the 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.

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.

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.

Further, as approved by the Board of Directors of the Society of Petroleum Engineers (SPE), Inc. , developed reserves are categorized based upon the producing status of the wells and/or reservoirs.

     (i) Producing reserves are expected to be recovered from completion intervals open at the time of the estimate and producing. Improved recovery reserves are considered to be producing only after an improved recovery project is in operation.

     (ii) Nonproducing reserves include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from completion intervals open at the time of the estimate, but which had not started producing, or were shut in for market conditions or pipeline connection, or were not capable of production for mechanical reasons, and the time when sales will start is uncertain. Behind-pipe reserves are expected to be recovered from zones behind casing in existing wells, which will require additional completion work or a future recompletion prior to the start of production.