Exhibit 99.1

www.approachresources.com | 6500 W. Freeway, Suite 800 Fort Worth, Texas 76116 | 817.989.9000 Company Presentation March 23, 2009

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 and financial and operating 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 filed with the Securities and Exchange Commission ("SEC") on March 13, 2009. 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 "resource" reserves, reserve "potential" 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 Company Presentation March 2009

Founded 2002 IPO November 14, 2007 Exchange/Ticker Market cap $119.7 mm(2) Shares outstanding 20.7 mm Company overview Core areas of operation(1) Portfolio highlights(1) (1)As of December 31, 2008. (2)Based on March 19, 2009 closing price and 20.7 mm shares outstanding. 211.1 Bcfe of proved reserves 48% proved developed, 82% natural gas 23.9 MMcfe/d 2008 average daily production 20+ year reserve life index 300,334 gross (199,818 net) acres 1,205 identified locations 445 producing wells General AREX Company Presentation March 2009

Key investment highlights High quality, long-lived asset base Low risk, repeatable, multi-year drilling inventory Financial flexibility Technically driven management team with a proven track record of unconventional resource exploration, evaluation and development Attractive valuation versus peers AREX: $0.75/Mcfe Peer average: $2.27/Mcfe Peer median: $2.00/Mcfe (1)Source: Tudor, Pickering, Holt & Co. Weekly Valuation Sheet, March 20, 2009, and AREX reports. Based on March 19, 2009 closing price of $5.79 per share, December 31, 2008 balance sheet and reported reserve estimates. Peer comparison - 2008 EV/Mcfe ($/Mcfe)(1) AREX Company Presentation March 2009 EV/Mcfe ($/Mcfe) $0 $1 $2 $3 $4 $5 $6 AREX ARD BRY BEXP CRZO CXO GMXR GDP ME PLL REXX

2008 Operational highlights Proved reserves increased 17% to 211.1 Bcfe, compared to 180.4 Bcfe at December 31, 2007 Production increased 65% to 8.8 Bcfe (23.9 MMcfe/d), compared to 2007 production of 5.3 Bcfe (14.5 MMcfe/d) We expanded our West Texas acreage position in the Canyon, Strawn and Ellenburger to 94,457 gross (63,510 net) acres We acquired the remaining 95% working interest in all depths below the top of the Strawn formation, 7.7 Bcfe of proved reserves, compression facilities and 75 miles of gathering lines in Ozona Northeast We drilled 96 (62.5 net) wells - 83 (54.5 net) productive and 13 (8 net) non-productive(2) We recompleted 6 wells in Cinco Terry and 6 wells in Ozona Northeast West Texas acreage position(1) (1)As of December 31, 2008. JCT wells as of July 1, 2008 acquisition. (2)Of the 13 (8 net) non-productive wells, 2 (0.5 net) were non-operated and non-economical in British Columbia, 1 (1 net) will be completed as a saltwater disposal well in East Texas, 7 (3.5 net) were P&A'd or J&A'd in Cinco Terry and 3 (3 net) were P&A'd or J&A'd in Ozona Northeast. Operational highlights AREX Company Presentation March 2009

2008 Financial highlights (1)Adjusted net income (a non-GAAP measure) reconciliation provided on page 20. (2)EBITDAX (a non-GAAP measure) reconciliation provided on page 21. (in millions, except per share data) AREX Company Presentation March 2009 Year Ended December 31, 2008 Year Ended December 31, 200 7 P ercent Increase Revenues $ 79,869 $ 39,114 104 % Net i ncome $ 23,386 $ 2,709 763 % N et income per diluted share $ 1.12 $ 0.24 A djusted net income (1) $ 23,483 $ 5,286 344 % Adjusted net income per diluted share $ 1.13 $ 0.47 EBITDAX (2) $ 63,201 $ 30,351 108 % EBITDAX per diluted share $ 3.03 $ 2.71

(1) Production and reserve growth Production growth (MMcfe/d) Proved reserves growth (Bcfe) (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)Pro forma for the Neo Canyon acquisition. 43.0% CAGR 28.6% CAGR AREX Company Presentation March 2009 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) Two rigs running through March 31, 2009, with operational flexibility to release these rigs, decrease capital expenditure budget down to approximately $12 million and still achieve stable to moderate production growth in 2009 Observations (2) 60 109 149 180 211 2004 2005 2006 2007 2008 4 14 18 19 23.9 2004 2005 2006 2007 2008

2008 Reserve summary and unrisked potential Reserve overview(1) Total reserves by category Reserve mix Oil 18% Gas 82% PUD 25% PD 24% Possible 12% Probable 18% (1) Estimates of proved, probable and possible reserves at December 31, 2008 are based on an independent engineering study of our oil and gas properties prepared by DeGolyer and MacNaughton. Resource reserve estimates are based on internal Company studies. Probable, possible and resource reserves are unrisked and unbooked. Resource 21% AREX Company Presentation March 2009 Oil/NGLs Gas Equivalent Category (MBbls) (MM cf) (MM cfe) Proved reserves Developed 3 ,014 8 4,217 1 02,298 Undeveloped 3,353 8 8,651 1 08,770 Total proved reserves 6,367 1 72,868 2 11,068 Probable reserves 2, 224 6 3,240 7 6,584 Possible reserves 2 ,084 3 9,915 5 2,419 Resource 3 ,079 7 3,184 9 1,658 Total 13,754 349,207 431,729

(1)Source: Tudor, Pickering, Holt & Co. small-cap peer group. Data from publicly-filed company reports. Operating as a low-cost producer: 2008 operating expenses comparison LOE & severance tax ($/Mcfe) 2008 LOE & severance tax(1) AREX: $1.35/Mcfe Peer average: $2.22/Mcfe Peer median: $2.02/Mcfe AREX Company Presentation March 2009 $0 $1 $2 $3 $4 $5 AREX ARD BRY BEXP CRZO CXO GMXR GDP ME PLL REXX

Finding & Development Costs(1) AREX Company Presentation March 2009 Peer comparison: Drill-bit F&D cost Peer comparison: All-in F&D cost 2008 F&D cost metrics Drill-bit finding and development cost $2.11/Mcfe All-in finding and development cost, including revisions $2.64/Mcfe All-in finding and development cost, including revisions and the change in future development costs $2.88/Mcfe AREX: $2.11/Mcfe Peer average: $3.70/Mcfe Peer median: $2.77/Mcfe AREX: $2.64/Mcfe Peer average: $2.01/Mcfe Peer median: $2.75/Mcfe Drill-bit F&D ($/Mcfe) All-in F&D ($/Mcfe) (1)Source: Tudor, Pickering, Holt & Co. small-cap peer group. Data from publicly-filed company reports. F&D costs (non-GAAP) reconciliation and important disclosures provided on pages 22-23. -$24 -$20 -$16 -$12 -$8 -$4 $0 $4 $8 $12 $16 $20 $24 AREX ARD BRY BEXP CRZO CXO GMXR GDP ME PLL REXX $0 $1 $2 $3 $4 $5 $6 $7 $8 $9 $10 $11 $12 AREX ARD BRY BEXP CRZO CXO GMXR GDP ME PLL REXX

Ozona Northeast field Canyon Sands tight gas, Strawn and Ellenburger development Own substantially all working interest in all depths 80% NRI Legacy asset with significant remaining development potential 144.4 Bcfe estimated proved reserves, 100% operated Low decline rates (4%-6%) in mature wells 49,169 gross (44,044 net) acres Own or operate 140 miles of gathering lines 660 identified drilling locations Drilling inventory map with JCT wells(1) Key highlights(1) (1)As of December 31, 2008. JCT wells from July 1, 2008 acquisition. AREX Company Presentation March 2009

Cinco Terry project Canyon Sands tight gas development +-52% WI & 39% NRI Ellenburger development 45.9 Bcfe estimated proved reserves 45,288 gross (19,466 net) acres 456 identified drilling locations Drilling inventory map(1) Key highlights(1) 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 December 31, 2008. AREX Company Presentation March 2009

North Bald Prairie prospect - East Texas Cotton Valley Lime, Bossier Shale, Bossier Sand, Cotton Valley Sands development 50% WI & +-40% NRI 20.8 Bcfe estimated proved reserves 9,301 gross (4,361 net) acres 89 locations identified Rodessa and Pettit behind pipe potential Acreage map(1) Key highlights(1) (1)As of December 31, 2008. AREX Company Presentation March 2009

British Columbia 25% non-operated WI 31,231 gross (7,395 net) acres Primary targets are Montney tight gas sands and Doig shale Exploratory plays Western Kentucky - Boomerang New Albany Shale 74,988 gross (44,759 net) undeveloped acres Long dated leases (2 year remaining primary + 5 year extensions remaining) provide long term option value on technology and gas prices After evaluating results from test wells, determine development program for the prospect Northern New Mexico - El Vado East Mancos Shale exploration 2,000 to 3,000 feet 90,357 gross (79,793 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 Currently, deferring 2009 capital expenditures AREX Company Presentation March 2009

Appendix A

Financial and operating guidance 2009 financial and operating guidance The table below sets forth the Company's current 2009 financial and operating guidance. The 2009 guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company's control, as further described on page 2 of this presentation. AREX Company Presentation March 2009 Current Guidance Production: Total (MMcfe) ................................ ...................... 8,700 - 9,4 00 Operating costs and expenses: Lease operating expense (per Mcfe) ........................... $ 0.85 - 0.95 Severance and production taxes (percent of oil and gas sales) ................................ .............................. 5 % - 6% Gene ral and administrative (per Mcfe) ........................ $ 0.90 - 1.00 Depletion, depreciation and amortization (per Mcfe) ...... $ 2.50 - 3.00

Ownership of management and certain beneficial owners at 12/31/2008 Equity ownership (1)As of most recent public filings, 4.3 million shares are owned by non-affiliate holders of 5% or more of our outstanding common stock. AREX Company Presentation March 2009 Number of Shares of Common Stock Owned (mm) Percent Management and Affiliates Yorktown Energy Partners ................................ ...................... 6.6 32 % Lubar Equity Fund, LLC ................................ .......................... 0.9 4 % Officers, directors and employees ................................ ............. 1. 3 6 % S ubtotal ................................ ................................ ......... 8.8 4 2 % Public Float 5 % Beneficial Owners (1) ................................ .......................... 4.3 21 % O ther Stockholders ................................ ............................... 7. 6 3 7 % S ubtotal ................................ ................................ ......... 11.9 58 % Total ................................ ................................ ............... 20.7 100 %

Financial and operating data (unaudited) $ thousands, except per unit metrics (1)EBITDAX (a non-GAAP measure) reconciliation provided on page 21. AREX Company Presentation March 2009 Three Months Ended December 31 , Twelve Months Ended December 31 , 2008 2007 2008 2007 Revenues (in thousands): Gas $ 10,91 9 $ 9,387 $ 58,819 $ 33,497 Oil 3,190 1,987 16,413 5,062 NGLs 583 366 4,637 555 Total oil and gas sales 14,69 2 11,740 79,869 39,114 Realized gain on commodity derivatives 3,612 1,409 2,936 4,732 Total oil and gas sales including derivative impact $ 18,30 4 $ 13,149 $ 82,805 $ 43,846 Production: Gas (MMcf) 2,16 5 1,423 7,09 2 4,801 Oil (MBbls) 55 22 175 72 NGLs (MBbls) 2 7 7 10 2 12 Total (MMcfe) 2,659 1,597 8,75 5 5,305 Average prices: Gas (per Mcf) $ 5.04 $ 6.60 $ 8.29 $ 6.98 Oil (per Bbl) 58. 00 90.32 93. 7 9 70.31 NGLs (per Bbl) 21.59 52.29 45. 4 6 46.25 Total (per Mcfe) $ 5.53 $ 7.35 $ 9.12 $ 7.37 Realized gain on commodity derivatives (per Mcfe) 1.36 0. 8 8 0.34 0.89 Total per Mcfe including derivative impact $ 6.89 $ 8.23 $ 9.46 $ 8.26 Costs and expenses (per Mcfe): Lease operating expense $ 0.95 $ 0.65 $ 0.87 $ 0.72 Severance and production taxes 0.49 0.32 0.48 0 .31 Exploration ? 0.16 0.17 0.17 Impairment of non - producing properties 2.40 0.17 0.73 0.05 General and administrative 1.2 0 5.36 1.01 2.39 Depletion, depreciation and amortization 2.80 2.43 2.71 2.47 EBITDAX (1) $ 11,572 $ 7,515 $ 63,201 $ 30,351

Condensed balance sheet data (unaudited) $ thousands AREX Company Presentation March 2009 December 31 , December 31, Unaudited Consolidated Balance Sheet Data (in thousands): 2008 2007 Cash and cash equivalents $ 4,077 $ 4,785 Other current assets 30, 760 12,02 1 Property and equipment, net, successful efforts method 303,404 230,819 Other assets - 1,101 Total assets $ 338,241 $ 248,726 Current liabilities $ 30,775 $ 22,017 Long - term debt 43,537 - Other long - term liabilities 40,116 26,890 Stockholders' equity 223,813 199,819 Total liabilities and sto ckholders' equity $ 338,241 $ 248,726

Adjusted net income reconciliation (unaudited) $ thousands AREX Company Presentation March 2009 In this presentation, we provide the non-GAAP financial measure adjusted net income, which excludes the following items: impairment of long-lived assets, unrealized, pre-tax gain on commodity derivatives, and related income taxes. In accordance with SFAS 144, we reviewed our long-lived assets to be held and used, including proved and unproved oil and gas properties, accounted for under the successful efforts method of accounting. As a result of this review of the recoverability of the carrying value of our assets during 2008, we recorded an impairment of non-producing oil and gas properties of $6.4 million. We also recorded an impairment of investment of $917,000 in 2008 relating to our equity investment in the Canadian operator of our Northeast British Columbia project. In addition, historically, we have not designated our derivative instruments as cash-flow hedges. We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our consolidated statements of operations under "unrealized gain (loss) on commodity derivatives." The unrealized, pre- tax gain on commodity derivatives was $3.1 million and $7.1 million for the three and twelve months ended December 31, 2008, respectively. The amounts included in the calculation of adjusted net income below were computed in accordance with GAAP. We believe adjusted net income is useful to investors because it provides readers with a more meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. Three Months Ended December 31 , Twelve Months Ended December 31 , 2008 2007 2008 2007 Net (loss) income $ ( 152 ) $ (1,793 ) $ 23,386 $ 2,709 Impairment of non - producing properties 6,379 267 6,379 267 Impairment of investment 917 - 917 - Unrealized (gain) loss on commodity derivatives (3,089 ) 1,520 (7,149 ) 3,637 Related income tax effe ct for above items (1,430 ) (608 ) (50 ) (1,327 ) Adjusted net income (loss) $ 2,625 $ (614 ) $ 23,483 $ 5,286 Adjusted net income (loss) per diluted share $ 0. 13 $ (0.04 ) $ 1. 13 $ 0.47

EBITDAX reconciliation (unaudited) $ thousands AREX Company Presentation March 2009 EBITDAX is reconciled to the GAAP measure of net income and included in this presentation 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) impairments of long-lived assets, (3) depletion, depreciation and amortization expense, (4) share-based compensation expense, (5) unrealized loss (gain) on commodity derivatives, (6) interest expense and (7) 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. Three Months Ended December 31 , Twelve Months Ended December 31 , 2008 2007 2008 2007 Net (loss) income $ (152 ) $ (1,793 ) $ 23,386 $ 2,709 Exploration - 250 1,478 883 Impairment of non - producing properties 6,379 267 6,379 267 Depletion, depreciation and amortization 7,453 3,881 23,710 13,098 Share - based compensation 300 4,471 1,100 4,646 Impairment of investment 917 - 917 - Unrealized (gain) loss on commodity derivatives ( 3,089 ) 1,520 (7,149 ) 3,637 Interest expense, net 355 2,157 1,269 5,21 9 Income tax (benefit) provision (591 ) (3,238 ) 12, 111 (108 ) EBITDAX $ 11 , 572 $ 7,515 $ 63 , 201 $ 30, 351 EBITDAX per diluted share $ 0. 5 6 $ 0.49 $ 3.0 3 $ 2.7 1

Finding and development costs reconciliation (unaudited) We believe that providing measures of finding and development, or F&D, cost is useful to assist 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 annual report on Form 10-K filed with the SEC on March 13, 2009. 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. 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 Approach to calculate its F&D costs may differ significantly from methods used by other companies to compute similar measures. As a result, Approach's F&D costs may not be comparable to similar measures provided by other companies. The following table reflects the reconciliation of our estimated finding and development costs for the year ended December 31, 2008 to the information required by paragraphs 11 and 21 of Statement of Financial Accounting Standard No. 69: AREX Company Presentation March 2009

F&D costs reconciliation (unaudited) - cont. Drill-bit finding and development ("F&D") costs are calculated by dividing the sum of exploration costs and development costs for the year, by the total of reserve extensions and discoveries for the year. All-in F&D costs, including revisions, are calculated by dividing the sum of property acquisition costs, exploration costs and development costs for the year, by the total of reserve extensions, discoveries, purchases and all revisions for the year. All-in F&D costs, including revisions and the change in future development costs, are calculated by dividing the sum of property acquisition costs, exploration costs, development costs and the change in future development costs from the prior year, by the total of reserve extensions, discoveries, purchases and all revisions for the year. (1)Includes $3.5 million in non-cash asset retirement obligations recorded in 2008. Cost summary (in thousands) Property acquisition costs Unproved properties $ 2,695 Proved properties 1 2,189 Exploration costs 5,007 Development costs (1) 84,193 Total costs incurred $ 104,084 Future development costs (in thousands) 2007 $ 191,738 2008 201,259 Change in future development costs $ 9,521 Reserve summary (MMcfe) Balance?December 31, 2007 180,400 Extensions and discoveries 42,249 Purchases of minerals in place 7,711 Production (8,755 ) Revisions to previous estimates (10,537 ) Balance?December 31, 2008 211,068 Finding and development cos ts ($/Mcfe) Drill - bit finding and development cost $ 2.11 All - in finding and development cost, including revisions $ 2.64 All - in finding and development costs, including revisions and change in future development costs $ 2.88

Current natural gas hedges(1) Hedging positions AREX Company Presentation March 2009 (1)As of March 31, 2009. Volume (MMBtu) $/MMBtu Period Monthly Total Floor Ceiling Fixed NYMEX - Henry Hub Costless collars 2009 ................................ ........................ 180,000 1 ,620,000 $ 7.50 $ 10.50 Costless collars 2009 ................................ ...... 130,000 1 ,170,000 $ 8.50 $ 11.70 Fixed price swap 2 nd - 4 t h quarter 2009 ................................ ..... 150,000 1,350,000 $ 4.50 WAHA differential Fixed price swaps 2009 ................................ ..................... 200,000 1 ,800,000 $ (0.61 ) 3 rd quarter 2009 ................................ ............................. 300,000 900,000 $ (0.58 )