exv99w1

Exhibit 99.1

DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

July 29, 2010

Approach Resources, Inc.
6500 West Freeway
Suite 800
Fort Worth, TX 76116

Gentlemen:

Pursuant to your request, we have conducted a reserves evaluation of the net proved crude oil, condensate, natural gas liquids (NGL), and natural gas reserves, as of June 30, 2010, of certain properties owned by Approach Resources, Inc. (Approach). The properties appraised are located in Limestone, Crockett, and Schleicher Counties, Texas. Approach has represented that these properties account for 100 percent of Approach’s net proved reserves as of June 30, 2010. The net proved reserves estimates prepared by us have been prepared in accordance with the reserves definitions of Rules 4—10(a) (1)—(32) of Regulation S—X of the Securities and Exchange Commission (SEC) of the United States.

Reserves included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after June 30, 2010. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Approach after deducting all interests owned by others. Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as that portion of the total gas to be delivered into a gas pipeline for sale after separation, processing, fuel use, and flare. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 14.65 pounds per square inch absolute (psia). Condensate reserves estimated herein are those to be recovered by conventional lease separation.



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Estimates of oil, condensate, NGL, and natural gas should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this evaluation were obtained from reviews with Approach personnel, Approach files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Approach with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

Estimates of reserves were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis



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of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Definition of Reserves

Petroleum reserves estimated by us included in this report are classified by degree of proof as proved and are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. Proved reserves classifications used by us in this report are in accordance with the reserves definitions of Rules 4—10(a) (1)—(32) of Regulation S—X of the SEC. The petroleum reserves are classified as follows:

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.



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(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



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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 [section 210.4—10 (a)



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Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs:

Oil Prices

Prices used in this evaluation were based on local differentials to the West Texas Intermediate (WTI) price of $75.99 per barrel. The WTI base price is the average price for WTI crude on the first day of the month for the period July 1, 2009, through June 1, 2010. Local differentials are based on the difference between the actual price received and the WTI price on the first day of each month between July 1, 2009, and June 1, 2010. The weighted average price over the lives of the properties was $71.99 per barrel.

Natural Gas Prices

Prices used in this evaluation were based on local differentials to a Henry Hub gas price of $4.085 per million British thermal units (MMBtu). The Henry Hub base price is the average price for Henry Hub gas on the first day of each month for the period July 1, 2009, through June 1, 2010. Local differentials are based on the difference between the actual price received and the Henry Hub price on the first day of each month between July 1, 2009, through June 1, 2010. The weighted average price over the lives of the properties was $3.879 per thousand cubic feet.

For the Angus and Ozona Northeast areas, contractual arrangements for gas sales have been taken into account in the preparation of this report. As of June 30, 2010, gas in the Angus area is sold at a differential to Henry Hub of -$0.231 per MMBtu. Per contractual arrangement, this differential will be



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reduced to -$0.211 per MMBtu as of December 1, 2012. Gas from the northeast Ozona area, as of June 30, 2010 is being sold at a differential of $0.52 per MMBtu. As of April 1, 2011, gas from the Northeast Ozona area will be sold at a differential of -$0.211 per MMBtu.

NGL Prices

Prices used in this evaluation were based on the average price received on the first day of each month for the period July 1, 2009, through June 1, 2010. The weighted average price, held constant over the lives of the properties, was $36.12 per barrel.

Operating Expenses and Capital Costs

Estimates of operating expenses based on current expenses were used for the lives of the properties with no increases in the future based on inflation. In certain cases, future expenses, either higher or lower than current expenses, may have been used because of anticipated changes in operating conditions. Future capital expenditures were estimated using 2010 values and were not adjusted for inflation.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the June 30, 2010, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.

Summary of Oil and Gas Reserves

Our estimates of the net proved reserves attributable to the properties appraised, as of June 30, 2010, are summarized by geographic area as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf):



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Net Proved Reserves as of June 30, 2010

Estimated by DeGolyer and MacNaughton

Oil and

Natural Gas

Sales

Condensate

Liquids

Gas

(Mbbl)

(MMcf)

Proved Developed

Angus

1,161

2,872

16,204

North Bald Prairie

1,493

Ozona Northeast

616

6,628

49,184

Total Proved Developed

1,777

9,500

66,881

Proved Undeveloped

Angus

1,834

2,145

12,046

North Bald Prairie

13,516

Ozona Northeast

981

6,822

47,454

Total Proved Undeveloped

2,815

8,967

73,016

Total Proved

4,592

18,467

139,897

In our opinion, the information relating to estimated proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries — Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4—10(a) (1)—(32) of Regulation S—X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S—K of the Securities and Exchange Commission; provided, however, that the as-of date of this report does not coincide with the fiscal year of Approach.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Approach. Our fees were not contingent on



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the results of our evaluation. This letter report has been prepared at the request of Approach. DeGolyer and MacNaughton has used all data, assumptions, procedures, and methods that it considers necessary to prepare this report.


		Submitted,

		/s/ DeGolyer and MacNaughton
		DeGOLYER and MacNAUGHTON
		Texas Registered Engineering Firm F-716


		/s/ Paul J. Szatkowski, P.E.

		Paul J. Szatkowski, P.E.
[SEAL]		Senior Vice President
		DeGolyer and MacNaughton

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Paul J. Szatkowski, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

	1.		That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Approach dated July 29, 2010, and that I, as Senior Vice President, was responsible for the preparation of this report.

	2.		That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1974; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists; and that I have in excess of 35 years of experience in the oil and gas reservoir studies and reserves evaluations.


		/s/ Paul J. Szatkowski, P.E.

		Paul J. Szatkowski, P.E.
[SEAL]		Senior Vice President
		DeGolyer and MacNaughton