Exhibit 99.3

2Q 2010 Quarterly Results August 3, 2010

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August 3,2010 Slide 2 Forward-looking statements and cautionary statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of management regarding plans, strategies, objectives, anticipated financial and operating results of the Company, including as to the Company's drilling program, estimated reserves and drilling locations, hedging activities, capital expenditures, financial and operating guidance, 3-D seismic data interpretation and potential value added by processing NGLs included in the presentation. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate and believed to be reasonable by management. When used in this presentation, the words "will," "potential," "believe," "intend," "expect," "may," "should," "anticipate," "could," "estimate," "plan," "predict," "project" or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. In particular, careful consideration should be given to the cautionary statements and risk factors described in the Company's Annual Report on Form 10-K filed with the Securities and Exchange Commission ("SEC") on March 12, 2010. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. The Company uses the terms "estimated ultimate recovery," "EUR," reserve "potential," "upside" or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's rules may prohibit the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. Reconciliations and definitions for non-GAAP financial measures and other measures used throughout this presentation are included in the appendix to this presentation. Information regarding non-GAAP financial measures and other measures also is posted on the Non-GAAP Financials page of the Company's website at www.approachresources.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website. AREX 2Q 2010 QUARTERLY RESULTS

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Areas of operation (as of 6/30/2010) June 24, 2010 Slide 3 AREX 2Q 2010 QUARTERLY RESULTS Notes: EV per proved Mcfe based on closing price of $6.74 per share on 7/30/2010, 21.1 mm shares outstanding at 6/30/2010, and net debt of $41.9 mm at 6/30/2010. Enterprise value (EV) ($M) 184,656 $ MY'10 Proved reserves (MMcfe) 278,251 EV per proved Mcfe ($/Mcfe) 0.66 $

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Production rising 2010 Average daily production (MMcfe/d) 8% ? Estimated average daily production for July 2010 is an 8% increase over 2Q 2010. August 3,2010 Slide 4 AREX 2Q 2010 QUARTERLY RESULTS

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2Q 2010 financial highlights 2Q 2010 highlights (in thousands, except per share amounts) August 3,2010 Slide 5 AREX 2Q 2010 QUARTERLY RESULTS Three Months Ended June 30 , Variance 2010 2009 (%) Revenues ................................. ................................. ................... $ 13,155 $ 9,915 e 33 % Net income (loss) ................................. ................................. ....... $ 1,551 $ (671 ) e 331 % Net income (loss) per diluted share ................................. ........... $ 0.07 $ (0.03 ) e 327 % Adjusted net income ................................. ................................. .. $ 2,806 $ 2,180 e 29 % Adjusted net income per diluted share ................................. ...... $ 0.13 $ 0.10 e 27 % EBITDAX ................................. ................................. ..................... $ 10,345 $ 10,210 e 1 % EBITDAX per diluted share ................................. ......................... $ 0.49 $ 0.49 e ? % Realized price ($/Mcfe) (excluding commodity derivatives) ....... $ 5.90 $ 4.35 e 36 %

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M-Y 2010 proved reserves highlights August 3,2010 Slide 6 Estimated proved reserves at 6/30/2010 AREX 2Q 2010 QUARTERLY RESULTS Proved reserves increased 27% to 278 Bcfe Proved reserves now 50% oil and NGLs and 50% natural gas Oil & NGLs increased 173% to 23 MMBbls Proved developed reserves increased 44% to 134.5 Bcfe; proved reserves now 48% PDP PV-10 increased 115% to $278 MM M-Y '10 all-in F&D cost $0.46/Mcfe

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M-Y 2010 proved reserves August 3,2010 Slide 7 Estimated proved reserves at 6/30/2010 AREX 2Q 2010 QUARTERLY RESULTS June 30, 2010 December 31, 2009 Natural Gas Oil NGLs Total Natural Gas Oil NGLs Total Percent (MMcf) (MBbls) (MBbls) (MMcfe) (MMcf) (MBbls) (MBbls) (MMcfe) Change Ozona Northeast 96,63 8 1,597 13,450 186,921 126,615 1,359 ? 134,767 39 % Cinco Terry 28,250 2,995 5,017 76,321 26,235 2,979 4,094 68,677 11 % North Bald Prairie 15,009 ? ? 15,009 15,484 ? ? 15,484 (3 )% Total 139,897 4,592 18,467 278,251 168,334 4,338 4,094 218,928 27 %

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Well-balanced reserve mix Reserve mix at December 31, 2009 Reserve mix at June 30, 2010 August 3,2010 Slide 8 23% Oil & NGLs 77% Natural Gas 43% Proved Developed 57% Proved Undeveloped 48% Proved Developed 52% Proved Undeveloped 50% Oil & NGLs 50% Natural Gas AREX 2Q 2010 QUARTERLY RESULTS

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Historical performance CAGR 30% CAGR 25% Production growth (MMcfe/d) Reserve growth (Bcfe) AREX 2Q 2010 QUARTERLY RESULTS Note: 2010-E production based on the midpoint of production guidance, or 9,150 MMcfe. August 3,2010 Slide 9

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Future outlook: increase oil & NGL production Begin processing natural gas from Ozona Northeast after 1Q 2011 Processing in Ozona Northeast and continued development in Cinco Terry increase oil and NGL production in 2011 and beyond (6:1 conversion) Oil & NGLs as a % of total production August 3,2010 Slide 10 AREX 2Q 2010 QUARTERLY RESULTS

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$7.50/Mcf Ozona Northeast - creating more value (Part I) Begin processing natural gas production from Ozona Northeast after 1Q 2011 Processing results in $1.25/Mcf potential value added to current revenue stream Key assumptions Commodity prices: $5.00/MMBtu of natural gas $40.00/Bbl of NGLs 1,250 Btu per Mcf Notes: Upon expiration of Ozona Northeast wellhead contract. Potential value added to revenue stream is forward-looking and based on price and other assumptions set forth above. Actual results will vary. Please see forward-looking statements and cautionary statements on page 2 of this presentation. Excludes all costs and effects of transportation, marketing, fuel shrink, line loss and other charges. $- $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $/Mcf Dry Gas (1,000 Btu) $5.00 $6.25 OZNE - Wet Gas (1,250 Btu) OZNE - Processing Wet Gas $7.50 High BTU Benefit NGL Benefit 25% 20% 1 MMBtu x $5.00 = $5.00/Mcf 1.25 MMBtu x $5.00 = $6.25/Mcf 1 Mcf ^ 0.70 MMbtu (30% shrink) & 0.1 Bbls of NGLs 0.70 MMBtu x $5.00 = $3.50 0.1 Bbls x $40.00 = $ 4.00 April 2011 Current August 3,2010 Slide 11 Premium production realization AREX 2Q 2010 QUARTERLY RESULTS

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Ozona Northeast - creating more value (Part II) August 3,2010 Slide 12 Premium, net estimated ultimate recovery ("EUR") AREX 2Q 2010 QUARTERLY RESULTS Begin processing natural gas production from Ozona Northeast after 1Q 2011 Processing is expected to result in a 25% increase in net EUR, comprised of 44% NGLs, 6% oil and 50% natural gas, which reflects the process of shrinking the natural gas production and recovering the NGLs

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Appendix Financial tables & non-GAAP and other financial measures

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Results of operations (unaudited) August 3,2010 Slide 14 AREX 2Q 2010 QUARTERLY RESULTS Three Months Ended June 30, Six Months Ended June 30, 2010 2009 2010 2009 Revenues (in thousands) Gas ................................. ................................. ................................. ...................... $ 6,864 $ 5,326 $ 14,546 $ 11,936 Oil ................................. ................................. ................................. ........................ 3,940 3,182 7,495 5,210 NGLs ................................. ................................. ................................. .................... 2,352 1,407 4,334 2,834 Total oil and gas sales ................................. ................................. ...................... 13,155 9,915 26,375 19,980 Realized gain on commodity derivatives ................................. ................................ 1,768 4,444 1,998 7,625 Total oil and gas sales including derivative impact ................................. ......... $ 14,924 $ 14,359 $ 28,373 $ 27,605 Production Gas (MMcf) ................................. ................................. ................................. ......... 1,558 1,624 2,982 3,395 Oil (MBbls) ................................. ................................. ................................. .......... 54 57 101 116 NGLs (MBbls) ................................. ................................. ................................. ....... 58 52 104 120 Total (MMcfe) ................................. ................................. ................................. 2,231 2,282 4,212 4,815 Total (MMcfe/d) ................................. ................................. .............................. 24.5 25.1 23.3 26.6 Average prices Gas (per Mcf) ................................. ................................. ................................. ...... $ 4.41 $ 3.28 $ 4.88 $ 3.52 Oil (per Bbl) ................................. ................................. ................................. ......... 73.26 55.60 74.27 44.83 NGLs (per Bbl) ................................. ................................. ................................. ..... 40.33 26.84 41.65 23.54 Total (per Mcfe) ................................. ................................. ............................... $ 5.90 $ 4.35 $ 6.26 $ 4.15 Realized gain on commodity derivatives (per Mcfe) 0.79 1.95 0.47 1.58 Total including derivative impact (per Mcfe) ................................. .................. $ 6.69 $ 6.30 $ 6.73 $ 5.73 Costs and expenses (per Mcfe) Lease operating ................................. ................................. ................................. ... $ 0.99 $ 0.77 $ 0.96 $ 0.86 Severance and production taxes ................................. ................................. ......... 0.27 0.22 0.31 0.19 Exploration ................................. ................................. ................................. .......... 0.08 ? 0.40 ? General and administrative ................................. ................................. ................ 0.98 0.98 1.11 1.05 Depletion, depreciation and amortization ................................. .......................... 2.25 2.73 2.57 2.74

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Summary financial information August 3,2010 Slide 15 AREX 2Q 2010 QUARTERLY RESULTS Unaudited Consolidated Balance Sheet Data June 30, December 31, (in thousands) 2010 2009 Cash an d cash equivalents $ 293 $ 2,685 Other current assets 15,591 9,318 Property and equipment, net, successful efforts method 322,542 304,483 Other assets 2,518 2,440 Total assets $ 340,944 $ 318,926 Current liabilities $ 24,169 $ 21,996 Long - term debt 42,169 32,319 Other long - term liabilities 48,070 44,115 Stockholders' equity 226,536 220,496 Total liabilities and stockholders' equity $ 340,944 $ 318,926

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Summary financial information August 3,2010 Slide 16 AREX 2Q 2010 QUARTERLY RESULTS Unaudited Consolidated Cash Flow Data Six Months Ended June 30, (in thousands) 2010 2009 Net cash provided (used) by: Operating activities $ 18,332 $ 11,186 Investing activities $ (30,234 ) $ (16 ,545 ) Financing activities $ 9,512 $ 2,700 Effect of foreign currency translation $ (2 ) $ (1 )

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Adjusted net income reconciliation (unaudited) (in thousands, except per share amounts) The amounts included in the calculation of adjusted net income and adjusted net income per diluted share below were computed in accordance with GAAP. We believe adjusted net income and adjusted net income per diluted share are useful to investors because they provide readers with a more meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. August 3,2010 Slide 17 AREX 2Q 2010 QUARTERLY RESULTS Three Months Ended June 30, Six Months E nded June 30, 2010 2009 2010 2009 Net income (loss) $ 1,551 $ (671 ) $ 5,114 $ 197 Adjustments for certain non - cash items: Unrealized loss (gain) on commodity derivatives 1,901 4,320 (3,194 ) 2,175 Related income tax effect (646 ) (1,469 ) 1,086 (740 ) Adjusted net income $ 2,806 $ 2,180 $ 3,006 $ 1,632 Adjusted net income per diluted share $ 0.13 $ 0.10 $ 0.14 $ 0.08

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EBITDAX reconciliation (unaudited) (in thousands, except per share amounts) We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss (gain) on commodity derivatives, (5) interest expense and (6) income taxes. EBITDAX is not a measure of net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator of a company's ability to internally fund development and exploration activities. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. Quarterly RESULTS - August 3,2010 Slide 18 AREX 2Q 2010 QUARTERLY RESULTS Three Months Ended June 30, Six Months Ended June 30, 2010 2009 2010 2009 Net income (loss) $ 1,551 $ (671 ) $ 5,114 $ 197 Exploration 18 7 ? 1,667 ? Depletion, depreciation and amortization 5,010 6,223 10,845 13,171 Share - based compensation 416 341 996 1,020 Unrealized loss (gain) on commodity derivatives 1,901 4,320 (3,194 ) 2,175 Interest expense, net 550 457 1,016 902 Income tax provision (benefit) 730 (460 ) 2,878 1,061 EBITDAX $ 10,345 $ 10,210 $ 19,322 $ 18,526 EBITDAX per diluted share $ 0.49 $ 0.49 $ 0.91 $ 0.89

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M-Y 2010 F&D costs reconciliation (unaudited) August 3,2010 Slide 19 AREX 2Q 2010 QUARTERLY RESULTS All-in finding and development ("F&D") costs, including revisions, are calculated by dividing the sum of property acquisition costs, exploration costs and development costs for the period by the total of reserve extensions, discoveries and all revisions for the period. We believe that providing the above measures of F&D cost is useful to assist in an evaluation of how much it costs the Company, on a per Mcfe basis, to add proved reserves. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our previous SEC filings and to be included in our annual report on Form 10-K to be filed with the SEC on or before March 16, 2011. Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods before the periods in which related increases in reserves are recorded, and development costs may be recorded in periods after the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases (or decreases) in reserves independent of the related costs of such increases. Further, all-in F&D costs at June 30, 2010, are materially lower than the Company's historical, all-in F&D costs due to the increase in proved reserves resulting from future processing of NGLs in Ozona Northeast at no additional capital cost. As a result of the above factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in our filings with the SEC, we cannot assure you that the Company's future F&D costs will not differ materially from those set forth above. Further, the methods used by us to calculate F&D costs may differ significantly from methods used by other companies to compute similar measures. As a result, our F&D costs may not be comparable to similar measures provided by other companies. The following table reconciles our estimated F&D costs for the six months ended June 30, 2010, to the information required by paragraphs 11 and 21 of ASC 932-235:

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M-Y 2010 F&D costs reconciliation (unaudited) - cont. August 3,2010 Slide 20 AREX 2Q 2010 QUARTERLY RESULTS As of June 30, 2010 Cost summ ary (in thousands) Property acquisition costs Unproved properties $ 1,231 Proved properties 19 Exploration costs 1,920 Development costs 26,089 Total costs incurred $ 29,259 Reserve summary (MMcfe) Bal ance?December 31, 2009 218,928 Extensions and discoveries 1,867 Purchases of minerals in place ? Production (4,212 ) Revisions to previous estimates NGL recovery - related revisions 54,182 Price - related revisions 6,240 Perfo rmance - related revisions 1,246 Total revisions to previous estimates 61,668 Balance?June 30, 2010 278,251 Finding and development costs ($/Mcfe) All - in F&D cost, including revisions $ 0.46

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M-Y 2010 PV-10 reconciliation (unaudited) August 3,2010 Slide 21 AREX 2Q 2010 QUARTERLY RESULTS The present value of our proved reserves, discounted at 10% ("PV-10"), was estimated at $277.8 million at June 30, 2010, and was calculated based on the first-of-the-month, twelve-month average prices for natural gas, oil and NGLs, or $4.09 per MMBtu of natural gas, $75.99 per Bbl of oil and $36.12 per Bbl of NGLs, respectively. PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their "present value." We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry. The following table reconciles PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP. As of June 30, 2010 (in thousands) PV - 10 $ 277,793 Less income taxes: Undiscounted future income taxes (235,984 ) 10% discount factor 138,459 Future discounted income taxes (97,525 ) Standardized measure of disco unted future net cash flows $ 180,268

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Contact Megan P. Brown, Investor Relations 817.989.9000 mbrown@approachresources.com www.approachresources.com