Exhibit 99.1

www.approachresources.com | 6500 W. Freeway, Suite 800 Fort Worth, Texas 76116 | 817.989.9000 Company Presentation September 2008

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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, production, 3-D seismic program, hedging activities, capital expenditures and other guidance 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. 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 and Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission ("SEC") on March 28, 2008 and August 6, 2008, respectively. 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 has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The Company uses the terms "estimated ultimate recovery," "EUR," "probable," "possible" and "non-proven" reserves, reserve "potential" or "upside" or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines may prohibit the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. AREX Investor Presentation September 2008

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About Approach Founded 2002 IPO November 14, 2007 Exchange/Ticker Nasdaq / AREX Market cap $293.6 mm(1) Shares outstanding 20.7 mm (1)Based on 8/28/2008 closing price and 20.7 mm shares outstanding. AREX Investor Presentation September 2008 General Management and company history Approach management/technical team has an average of 28 years of industry experience Track record of creating value for investors 1988: American Cometra (shallow & deep tight gas sands) Ross Craft joined American Cometra in 1988 American Cometra sold assets in two separate transactions in 1995 and 1997 to Range and Pioneer, respectively 1998: Athanor Resources (tight gas - U.S. & Tunisia) Funded by Yorktown Partners Sold U.S. assets in 2002 to Nuevo Energy 2002: Approach Resources founded Funded by Yorktown Partners Drilled first well in Ozona Northeast in 2004

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Areas of operation AREX Investor Presentation September 2008

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Key investment highlights High quality, long-lived asset base Low risk, repeatable, multi-year drilling inventory Sizeable acreage position in prospective unconventional resource plays Financial flexibility Technically driven management team with a proven track record of unconventional resource exploration, evaluation and development AREX Investor Presentation September 2008 2008E EV-to-EBITDA(X) AREX: 4.6x Peer median: 6.1x AREX: $1.73 EV/Mcfe proved reserves Peer median: $4.09 EV/Mcfe proved reserves (1)Source: JPMorgan Oil & Gas Exploration and Production Weekly E&P Comp Table, 8/29/2008. Peer comparisons(1) 2007A EV/Mcfe ($) 0 1 2 3 4 5 6 7 8 9 10 11 AREX BEXP CRZO CXO DPTR EPEX EAC END XCO GSX GDP ME MMR PVA PQ SGY SFY VQ WLL 1 2 3 4 5 6 7 8 9 10 11 AREX BEXP CRZO CXO DPTR EPEX EAC END XCO GSX GDP ME MMR PVA PQ SGY SFY VQ WLL

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Production and reserve growth Production growth (MMcfe/d) Proved reserves growth (Bcfe) (3) (2) Historic growth is organically driven Ozona Northeast historically represented majority of production and reserves Other development plays now contributing (Cinco Terry and North Bald Prairie) Currently five rigs running Observations (1)Pro forma for the November 14, 2007 acquisition of Neo Canyon Exploration, L.P.'s 30% working interest in Ozona Northeast, as if the acquisition occurred on January 1, 2007. (2)Based on production guidance of 8.5 Bcfe - 9.0 Bcfe released May 6, 2008. (3)Pro forma for the November 14, 2007 acquisition of the Neo Canyon interest, as if the acquisition occurred on December 31, 2006. (4)Estimates of proved, probable and possible reserves at June 30, 2008 are based on internal engineering studies prepared by Approach's reservoir engineers and reviewed by DeGolyer and MacNaughton. Resource reserve estimates are based on internal Company studies. Probable, possible and resource reserves are unrisked and unbooked. Reserve estimates at June 30, 2008 do not include reserves acquired in the July 1, 2008 acquisition of deep rights in Ozona Northeast, which is summarized on page 9 of this presentation. AREX Investor Presentation September 2008 (1) 23.2 - 24.6 (4) 60 109 149 180 194 2004 2005 PF 2006 2007 June 30, 2008 4 14 18 19 2004 2005 2006 2007 2008 (Projected)

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6/30/2008 Reserve summary and unrisked potential Reserve overview(1) Total reserves by category Reserve mix Oil 14% Gas 86% PUD 27% PD 21% Possible 13% Probable 21% Unbooked reserve potential: 210 Bcfe (1)Estimates of proved, probable and possible reserves at June 30, 2008 are based on internal engineering studies prepared by Approach's reservoir engineers and reviewed by DeGolyer and MacNaughton. Resource reserve estimates are based on internal Company studies. Probable, possible and resource reserves are unrisked and unbooked. Reserve estimates at June 30, 2008 do not include reserves acquired in the July 1, 2008 acquisition of deep rights in Ozona Northeast, which is summarized on page 9 of this presentation. AREX Investor Presentation September 2008 Resource 18% Oil/NGLs Gas Equivalent Category (MBbls) (Bcf) (Bcfe) Proved reserves Developed 1 ,778 7 3. 9 8 4. 5 Undeveloped 3,030 9 1.0 109.2 Total proved reserves 4 ,8 08 1 64.9 1 93. 7 Probable reserves 2 ,153 7 3. 5 8 6. 4 Possible reserves 1 ,658 42.6 5 2. 6 Resource 704 66. 8 7 1.0 Total 9, 3 23 3 47. 8 403.7

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Ozona Northeast field Canyon Sands tight gas, Strawn and Ellenburger development Legacy asset with significant remaining development potential 137.7 Bcfe estimated proved reserves at 6/30/2008, 100% operated Low decline rates (4%-6%) in mature wells 43,716 net acres (14,816 undeveloped) Own or operate 140 miles of gathering lines 739 identified drilling locations at 6/30/2008 Drilling inventory map with JCT wells(1) Key highlights 2008 plans Keep 1 to 2 rigs operating full time through 12/2008 Integration of reprocessed 3-D seismic (1)As of August 25, 2008. JCT wells as of July 1, 2008 acquisition. AREX Investor Presentation September 2008

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Ozona Northeast: Strawn/Ellenburger Acquisition - 7/1/2008(1) Strawn, Ellenburger recompletion potential Strawn: +-300' below Canyon Ellenburger: +-400' below Canyon Estimated deepening cost Strawn: +-$100,000/well Ellenburger: +-$110,000/well Expected reserve recovery Strawn: +-150 MMcfe/well, net recovery +-114 MMcfe/well Ellenburger: +-350 MMcfe/well, net recovery +-266 MMcfe/well Number of expected recompletions +-10 Strawn and +-5 Ellenburger wells Canyon recompletion potential (behind pipe) Estimated recompletion cost of +-$250,000/well Expected reserve recovery of +-480 MMcfe/well, net recovery +-364 MMcfe/well Number of expected recompletions: +-10 Canyon wells Transaction details Purchase price: $12 mm Estimated reserves: 7.7 Bcfe of proved reserves 1.7 Bcfe of probable reserves Production: 1.5 MMcfe/d current net production Purchase an additional 95% WI below top of Strawn Approach now owns substantially all WI above and below top of Strawn 75-mile gathering system Compression and associated equipment (1)Reserve estimates and estimates of reserve potential or upside with respect to the Strawn/Ellenburger acquisition were made by the Company's internal engineers without review by an independent petroleum engineering firm. These reserve estimates are not included in the Company's mid-year reserve estimates. Data used to make these estimates were obtained from the sellers and from publicly available information and may not be as complete as that which is available for the Company's other owned properties. The Company believes its estimates of proved reserves comply with criteria provided under current rules of the SEC. AREX Investor Presentation September 2008

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Ozona Northeast typical Canyon well Statistical, predictable results 513 - 486 MMcfe average gross EUR 391 - 366 MMcfe average net EUR (80% NRI) Premium price realization driven by high gas heat content 1,251 Btu per Mcfe Make-whole contract (wellhead) Realize slight premium to Henry Hub NYMEX (on per Mcfe basis) Estimated D&C costs $800k per well Estimated rate of return - based on 486 MMcfe average gross EUR 38% at $8.14 Henry Hub $627k NPV per well at 10% discount rate Expected breakeven at $3.25 Henry Hub Key observations Cumulative well cash flow profile at $8.14/Mcf Henry Hub Gas and $86.20/Bbl WTI Oil ($'000s) Drill & Complete AREX Investor Presentation September 2008 Type curve ($1,000) ($500) $0 $500 $1,000 $1,500 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Yrs.

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Cinco Terry project Canyon Sands tight gas development Ellenburger development 34.7 Bcfe estimated proved reserves at 6/30/2008 31,380 gross (14,406 net) acres (13,259 net undeveloped) 150 identified Canyon drilling locations at 6/30/2008 Drilled and completed 30 wells through 6/30/2008 (14 Ellenburger and 16 Canyon or Canyon/Ellenburger comingled) Drilling inventory map(1) Key highlights 2008 plans 2 to 4 rigs operating full-time through 12/2008 Drill horizontal test well into Wolfcamp Recently acquired 9,482 gross (4,899 net) acres Drill 42 Canyon/Ellenburger/Wolfcamp wells Multiple horizon potential Depth in feet 3,000 - 4,500 7,500 - 8,100 8,200 - 8,800 Wolfcamp/Sprayberry Canyon Sands Ellenburger (1)As of August 25, 2008. AREX Investor Presentation September 2008

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Cinco Terry typical Canyon well Statistical, predictable results +-50% WI & +-39% NRI 516 MMcfe average gross EUR 239 MMcfe average net EUR 90% POP 1,220 current Btu gas Fixed recoveries, fuel and shrink Estimated D&C costs (gross) $920k per well Estimated rate of return - 62% $644k NPV per well at 10% discount rate Key observations ($'000s) Cumulative well cash flow profile at $8.14/Mcf Henry Hub Gas, $90.20/Bbl WTI Oil, $54.12/Bbl NGL AREX Investor Presentation September 2008 Type curve Drill & Complete ($1,000) ($500) $0 $500 $1,000 $1,500 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Yrs.

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Cinco Terry typical Ellenburger well Statistical, predictable results +-50% WI & +-39% NRI 1,114 MMcfe average gross EUR 523 MMcfe average net EUR 90% POP 1,220 current Btu gas Fixed recoveries, fuel and shrink Estimated D&C costs (gross) $900k per well Estimated rate of return - 203% $2.0 mm NPV per well at 10% discount rate Key observations ($'000s) Cumulative well cash flow profile at $8.14/Mcf Henry Hub Gas, $90.20/Bbl WTI Oil, $54.12/Bbl NGL AREX Investor Presentation September 2008 Type curve Drill & Complete ($1,000) $0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Yrs ..

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North Bald Prairie prospect - East Texas Cotton Valley Lime, Bossier Shale, Bossier Sand, Cotton Valley Sands development 21.3 Bcfe estimated proved reserves at 6/30/2008 10,300 gross (4,900 net) acres (50% WI & +-40% NRI) 61 locations identified at 6/30/2008 Average EURs of 1.3 Bcfe (gross) Expected D&C cost per well $2.0 mm (gross) Rodessa and Pettit behind pipe D&C'd 8 producing wells since August 2007 Acreage map(1) Key highlights 2008 plans 1 rig operating full time Salt water disposal program Drill 8 CVL/Bossier/CVS wells (1)As of August 25, 2008. AREX Investor Presentation September 2008

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North Bald Prairie prospect- cross section AREX Investor Presentation September 2008

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North Bald Prairie - Bossier Shale Bossier Shale Cotton Valley Lime AREX Investor Presentation September 2008

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North Bald Prairie typical CVL, Bossier, CVS well Statistical, predictable results 50% WI & 40% NRI 1,302 MMcfe average gross EUR 500 MMcfe average net EUR Estimated D&C costs (gross) $2.0 mm per well at 6/30/2008 Estimated rate of return - 47% $915k NPV per well at 10% discount rate Key observations ($'000s) Cumulative well cash flow profile at $8.14/Mcf Henry Hub Gas AREX Investor Presentation September 2008 Type curve Drill & Complete ($2,000) ($1,000) $0 $1,000 $2,000 $3,000 $4,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Yrs ..

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British Columbia 25% non-operated working interest 28,860 gross (6,865 net) acres Primary targets are Montney tight gas sands and Doig shale Exploratory plays Western Kentucky - Boomerang New Albany Shale 74,000 gross (44,000 net) undeveloped acres Long dated leases (2 year prime + 5 year extensions remaining) provide long term option value on technology and gas prices After evaluating results from 2008 test wells, determine development program for the prospect Northern New Mexico - El Vado East Mancos Shale low cost exploration 2,000 to 3,000 feet 90,300 gross (81,000 net) undeveloped acres Proximity to several multi-million barrel fields (mostly crude oil) Additional prospectivity in Dakota, Morrison, Todilto and Entrada formations Rio Arriba County drilling moratorium has delayed drilling State rulemaking expected to begin 4Q 2008 for Eastern Rio Arriba County Currently, deferring 2008 capital expenditures AREX Investor Presentation September 2008

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Appendix A

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Financial strategy Maintain conservative financial policy $20.0 mm outstanding under our credit facility at 8/31/2008 Prudent use of leverage going forward Maintain ongoing financial flexibility to pursue acquisitions or accelerate development $100 mm borrowing base Operate our properties as a low cost producer Fund development drilling budget substantially from operating cash flow Employ commodity price hedging program Secure cash flow to fund development drilling program Use combination of swaps and collars Hedge basis differential AREX Investor Presentation September 2008

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Financial and operating guidance 2008 financial and operating guidance The 2008 financial and operating guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond our control, as described on page 2 of this presentation and in our SEC filings. AREX Investor Presentation September 2008

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Ownership of management and certain beneficial owners Equity ownership AREX Investor Presentation September 2008 Number of Shares of Common Stock Owned (mm) Percent Management and Affiliates Yorktown Energy Partners ................................. ........................ 7.5 36 % Lubar Equity Fund, LLC ................................. ........................... 0.9 5 % Officers, directors and employees ................................. .............. 1.1 5 % Subtotal ................................. ................................. ............. 9.5 41 % Certain Beneficial Owners ................................. ...................... 0.2 1 % Public Stockholders ................................. .............................. 11.0 58 % Total ................................. ................................. ................ 20.7 100 %

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Condensed balance sheet data $ thousands AREX Investor Presentation September 2008 June 30, December 31, 2008 2007 Cash and cash equivalents ................................. ................ $ 140 $ 4,785 Other current assets ................................. ....................... 24,665 12,362 Property and equipment, net, successful efforts method ........... 254,513 230,478 Other assets ................................. ................................. 920 1,101 Total assets ................................. ............................. $ 280,238 $ 248,726 Current liabilities ................................. .......................... $ 35,814 $ 22,017 Long - term debt ................................. ............................. 7,553 ? Other long - term liabilities ................................. ................ 32,830 26,890 Stockholders' equity ................................. ....................... 204,041 199,819 Total liabilities and stockholders' equity ........................... $ 280,238 $ 248,726

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Financial and operating data $ thousands, except per unit metrics (1)EBITDAX reconciliation provided on page 25. AREX Investor Presentation September 2008 Three Months Ended June 30, Six Months Ended June 30, 2008 2007 2008 2007 Revenues (in thousands): Gas ................................. ................................. ........ $ 18,572 $ 8,662 $ 33,444 $ 16,916 Oil ................................. ................................. ......... 4,165 975 7,250 2,065 NGLs ................................. ................................. ...... 1,407 53 2,468 101 Total oil and gas sales ................................. ............. 24,144 9,690 43,162 19,082 Realized (loss) gain on commodity derivatives ....................... (542 ) 88 (481 ) 2,24 3 Total oil and gas sales including derivative impact ........... $ 23,602 $ 9,778 $ 42,681 $ 21,325 Production: Gas (MMcf) ................................. ............................... 1,674 1,145 3,339 2,376 Oil (MBbls) ................................. ............................... 34 16 66 36 NGLs (MBbls) ................................. ............................ 26 1 47 3 Total (MMc fe) ................................. ........................ 2,036 1,251 4,016 2,608 Average prices: Gas (per Mcf) ................................. ............................ $ 11.10 $ 7.57 $ 10.02 $ 7.12 Oil (per Bbl) ................................. ............................. 121.29 59.76 110.10 57.83 NGLs per (Bbl) ................................. .......................... 53.93 36.92 52.61 33.39 Total (per Mcfe) ................................. ..................... $ 11.8 6 $ 7.74 $ 10.75 $ 7.32 Realized (loss) gain on commodity derivatives (per Mcfe) ......... (0.27 ) 0.07 (0.12 ) 0.86 Total per Mcfe including derivative impact .................... $ 11.59 $ 7.81 $ 10.63 $ 8.18 Costs and expenses (pe r Mcfe): Lease operating expenses ................................. ............ $ 0.91 $ 0.83 $ 0.81 $ 0.78 Severance and production taxes ................................. .... 0.57 0.30 0.48 0.29 Exploration ................................. .............................. 0.48 0.01 0.37 0.24 General and administrative ................................. .......... 0.89 0.97 0.94 1.05 Depletion, depre ciation and amortization ......................... 2.93 2.41 2.78 2.34 EBITDAX (1) ................................. ................................. .. $ 19,029 $ 7,232 $ 34,238 $ 15,912

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EBITDAX(1) reconciliation (unaudited) $ thousands (1)EBITDAX is presented in this presentation and reconciled to the generally accepted accounting principle ("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. 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. AREX Investor Presentation September 2008 Three Months Ended June 30, Six Months Ended June 30, 2008 2007 2008 2007 Net income ................................. ......................... $ 928 $ 2,990 $ 3,690 $ 2,409 Exploration ................................. ......................... 987 10 1,478 633 Depletion, deprecia tion and amortization .................... 6,025 3,017 11,241 6,108 Share - based compensation ................................. ...... 270 88 496 88 Unrealized loss (gain) on commodity derivatives ............ 9,672 (1,724 ) 14,551 2,902 Interest expense ................................. .................. 343 998 491 1,954 Income taxes ................................. ...................... 804 1,853 2,291 1,818 EBITDAX ................................. ............................ $ 19,029 $ 7,232 $ 34,238 $ 15,912 EBITDAX per diluted share ................................. ....... $ 0.91 $ 0.70 $ 1.64 $ 1.61

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Current natural gas hedges Hedging positions AREX Investor Presentation September 2008 Volume (MMBtu) $/MMBtu Period Monthly Total Floor Ceiling Fixed NYMEX - Henry Hub Costless collars 2008 ................................. ............... 178 ,000 1, 07 0 ,000 $ 7.50 $ 11.45 Costless collars (3 rd quarter 2008) ............................... 100,000 300,000 $ 7.00 $ 9.10 Costless collars ( 3 rd - 4 th quarter 2008) .......................... 200,000 1,2 00,000 $ 9.00 $ 12.20 Costle ss collars 2009 ................................. ............... 180,000 2,160,000 $ 7.50 $ 10.50 Costless collars 2009 ................................. ... 130,000 1,560,000 $ 8.50 $ 11.70 Fixed price swaps 4 th quarter 2008 ................................. ............. 100,000 300,000 $ 8.63 WAHA differential Fixed price swaps 2008 ................................. ............ 178 ,000 1, 07 0 ,000 (0.69 ) Fixed price swaps 2008 ( 3 rd - 4 th quarter) ....................... 100,000 6 00,000 (0.67 ) Fixed price swaps 2009 ................................. ............ 200,000 2,400,000 (0.61 )