Exhibit 99.1

Investor & Analyst Meeting Wolffork Shale Oil Resource Play October 18, 2010

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October 18, 2010 Slide 2 Forward-looking 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 Wolffork shale resource play, estimated oil and gas in place and recoverability of the oil and gas, estimated reserves and drilling locations, capital expenditures, typical well results and well profiles, and future production included in the presentation. These statements are based on certain assumptions made by the Company based on management's experience and technical analyses, 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," "profile," "model," 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" or "EUR," reserve "potential," "upside," "oil and gas in place" or "OGIP," "OIP," "OOIP" or "GIP," and 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. EUR estimates, drilling locations and OGIP estimates have not been risked by the Company. Actual locations drilled and quantities that may be ultimately recovered from the Company's interest will differ substantially. There is no commitment by the Company to drill all of the drilling locations that have been attributed these quantities. Factors affecting ultimate recovery include the scope of the Company's ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling and completion services and equipment, drilling results, leases expirations, regulatory approval, and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves, per well EUR, OGIP and upside potential may change significantly as development of the Company's oil and gas assets provides additional data. Cautionary statement regarding oil and gas quantities

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AREX Overview

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AREX management team October 18, 2010 Slide 4 J. Ross Craft, P.E. President, Chief Executive Officer and Director Steven P. Smart Executive Vice President and Chief Financial Officer J. Curtis Henderson Executive Vice President and General Counsel Ralph P. Manoushagian Executive Vice President - Land Qingming Yang , Ph.D. Vice President - Exploration

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Company overview (as of 9/30/2010, unless otherwise noted) October 18, 2010 Slide 5 Notes: Acreage as of 9/30/2010. Net acreage may change subject to partner elections on recent acreage acquisitions. EV per proved Boe based on closing price of $13.56 per share on 10/14/2010, 21.5 mm shares outstanding at 9/30/2010, and net debt of $50.7 mm at 9/30/2010. All BOE and Mcfe calculations are based on a 6 to 1 conversion ratio. Enterprise value (EV) ($M) $ 342,560 M-Y '10 Proved reserves (MBoe) 46,375 EV per proved Boe ($/Boe) $ 7.39 27 MMcfe/d Q3 2010 estimated daily production 46,375 MBoe of proved reserves 95% Permian Basin 50% Oil & NGLs 48% Proved developed 337,339 gross (224,763 net) acres 93,065 net acres in the Permian Basin 1,250+ identified locations Multi-zone potential Additional drilling locations expected from Wolffork development No reserves currently booked for Wolffork development 500+ producing wells Areas of operation AREX highlights

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(CHART) Production growth October 12, 2010 Slide 6 Average daily production (MMcfe/d) CURRENT PRODUCTION (EST. 3Q'10) Production growth: 2004-2010 CAGR 36% October 18, 2010 Slide 6 Note: 2010-E production based on the midpoint of production guidance, or 9,150 MMcfe. Current production based on 3Q'10 estimated average daily production.

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Reserve growth October 12, 2010 Slide 7 Proved reserves (MMBoe) Reserve growth: 2004-Mid Year 2010 CAGR 32% October 18, 2010 Slide 7 (CHART) 4% Oil & NGLs 6% Oil & NGLs 6% Oil & NGLs 11% Oil & NGLs 18% Oil & NGLs 23% Oil & NGLs 50% Oil & NGLs

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Well-balanced reserve mix September 24, 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 Reserve mix at December 31, 2009 Reserve mix at December 31, 2010 October 18, 2010 Slide 8

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Permian Basin assets October 18, 2010 Slide 9 1,175+ Identified locations 51% PDP AREX operated Ozona NE ^100% WI and ^80% NRI Cinco Terry ^52% WI and ^39% NRI 140,774 gross (93,065 net) acres Average cost basis ^$160 per acre Target formations: Clearfork, Wolfcamp, Canyon Sands, Strawn, Ellenburger Recent acreage acquisitions total 22,851 net acres (average WI ^94%) Project Pangea Proved reserves: 43.9 MMBoe Project Pangea: New acreage connects Ozona NE and Cinco Terry into 93,065 primarily contiguous net acres with multiple target pay zones. AREX - New Acreage AREX - New Acreage

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Wolffork Shale Oil Resource Play Permian Basin

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Wolfcamp Shale oil resource play Slide 11 Discovery Exploration Development Brown Field Extension Antrim Ohio New Albany FW Barnett Fayetteville Arkoma Woodford Haynesville Wolffork Niobrara Avalon Marcellus Eagle Ford Wolfberry October 18, 2010 Slide 11 Creating value through detailed technical evaluation and drill bit

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AREX acreage position Slide 12 Unconventional tight oil play with commingled production from Spraberry and Wolfcamp debris flow sediments Unconventional tight oil play with commingled production from Clearfork and Wolfcamp debris and turbidite flow sediments Wolffork Play Project Pangea October 18, 2010 Slide 12 Favorably located in Southern Midland Basin for Wolfcamp and Clearfork exploration

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Industry activity in Southern Midland Basin Slide 13 October 18, 2010 Slide 13 Recent activity in Southern Midland Basin

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Wolfberry play evolution - 1st 5 years Slide 14 Midland Basin Wolfberry Play Play activities during 1998-2002 Midland Upton Wolfberry Well ~28 miles Project Pangea October 18, 2010 Slide 14 1998 - 2002 ~100 Wolfberry Wells 2 Counties

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Slide 15 Wolfberry play evolution - 2nd 4 years Wolfberry Play Wolfberry Well ~28 miles Project Pangea October 18, 2010 Slide 15 Play activities during 2003-2006 Midland Upton Martin Ector Reagan 2003-2006 ~600 Wolfberry Wells 5 Counties

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Slide 16 Wolfberry Play Wolfberry play evolution - last 4 years Wolfberry Well ~28 miles Project Pangea October 18, 2010 Slide 16 2007-Present ~1,300 Wolfberry Wells 10 Counties Play activities during 2007-Present Midland 6) Howard Upton 7) Glasscock Martin 8) Reagan Ector 9) Irion Andrew 10) Crockett

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Wolffork play recognition Slide 17 Crockett County has been viewed as a gassy area - when oil and gas price ratio ranges from 16 to 20, operators are pursuing oily plays Almost all published, regional maps of the Permian Basin indicate that Northern Crockett County is located on top of the Ozona Arch - Wolfcamp was therefore "thought" to be thin / absent Wolfberry play was believed to stop at the "Big Lake Fault" in Southern Reagan County Traditionally, operators in this area acquired log data only for the zones of interests (e.g. Canyon, Strawn and Ellenburger) Few operators use mud loggers Drilled more than 400 wells in Crockett and Schleicher Counties since 2004 Collected mud logs for more than 200 wells Acquired full suite of logs for nearly 200 wells from surface casing to TD Conducted regional mapping to understand tectonic and basin history Developed a unique approach for well log correlation and shale play evaluation October 18, 2010 Slide 17 Why didn't others recognize the play? AREX

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Stratigraphic column for Project Pangea area Slide 18 System Series Stratigraphic Unit Grayburg San Andres Clearfork / Spraberry Dean Wolfcamp Cisco Canyon Strawn Mississippian Devonian Silurian Upper Middle Lower Ellenburger Guadalupian Leonardian Permian Pennsylvania Ordovician Ouachita-Marathon Thrusting Carbonate Ramp 310 MA 299 MA 275 MA 270 MA Absolute Time 444 MA 318 MA 488 MA October 18, 2010 Slide 18 Southern Midland Basin Val Verde Basin / Ozona Arch

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Structural cross-section across Big Lake Fault Slide 19 The Big Lake Fault does not affect the Wolfcamp thickness significantly in Wolffork play area Union Oil Co of Cal John R Scott Etal D 2 Texas Gulf Inc TXL 1 Texas Gulf Inc Wolters D 1 Borden Sam H Wolters 1 13,973' 5,022' 7,275' TD : 11,186 TD : 10,880 TD : 9,840 TD : 9,805 Big Lake Fault N S Ellenburger Cisco Wolfcamp Dean Spraberry October 18, 2010 Slide 19

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AREX Wolfcamp producers and shows Slide 20 University 42-23-12 University 42-23 8 Cinco Terry A 807 University 42-15 2 University 42-12 3 Addie Clayton 1101 PL Childress D 3A Bailey 315 October 18, 2010 Slide 20 Existing producers and show wells suggest that the Wolfcamp is hydrocarbon-charged AREX - Cinco Terry AREX - Ozona Northeast Baker A112 Wolfcamp Pilot Recompletions Wolfcamp Producers Wells with Wolfcamp Shows Wolfcamp Pilot Recompletions Wolfcamp Producers Wells with Wolfcamp Shows

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AREX shale play evaluation process Slide 21 Hydrocarbon generating potential TOC R0 - Tmax - TAI Shale Rock Properties Lithology - Mineralogy Hydrocarbons in Place Technical Limit Commercial Limit Thermal maturity for hydrocarbon generation Storage capacity Fracability - shale response to fracing stimulation Well spacing, performance, recovery Play boundary, leasing strategy D&C cost, technology, commodity price Execution Reserves, production optimization, NPV & IRR Natural Fracture Hydrocarbon pathway to wellbore October 18, 2010 Slide 21 Creating value through detailed technical evaluation

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Wolfcamp Shale - a world class source rock in oil window Slide 22 OIL ..6 ..9 1.20 1.35 2.0 3.0 Peak Wet Gas Dry Gas Peak Oil Floor Wet Gas Floor Dry Gas Floor R0 Ro: measures intensity of reflected light from polished vitrinite particles and reported as mean percent reflectance - the most commonly used technique for source rock thermal maturity determination. TOC (Total Organic Carbon Content) is the amount of material available to convert into hydrocarbons. A high percentage of TOC implies significant material (generally) available for hydrocarbon generation. Richness Good - Excellent Fair TOC (%) 2-10 1-2 <1 Poor TOC for Wolfcamp Shale from whole core of Baker A112: 2.24% - 7.24% October 18, 2010 Slide 22 Hydrocarbon Generating Potential Thermal Maturity Baker A112 Wolfcamp R0 ~0.95-0.97

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Storage space for oil and gas in Wolfcamp Shale Slide 23 Commonly observed core porosity values for established commercial shale plays Oil and Gas are stored in 3 forms in shale Matrix pore space Fractures Adsorption 6.8 8.2 4.7 4.6 6.0 3.9 1.8 6.1 1.5 8.4 10.1 9.3 10.1 10.0 4.2 6.6 10.5 1.4 10.4 7.1 10.9 0.0 2.0 4.0 6.0 8.0 10.0 12.0 Backscattered Electron Images Backscattered Electron Images 40 mm 2,000X 10 mm 7,500X October 18, 2010 Slide 23 Core Porosity for Baker A112 Core porosity (%)

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Slide 24 Natural Fractures Storage space for oil and gas in Wolfcamp Shale - cont. Numerous fractures can be seen from image log and core These natural fractures are near vertical and trend NE-SW The heavily fractured interval is vertically extensive, extending for over 1,700' Natural fractures can be reactivated via fracing stimulation and provide permeability conduits for hydrocarbon flow to wellbore October 18, 2010 Slide 24 Oil and Gas are stored in 3 forms in shale Matrix pore space Fractures Adsorption Core Photo Image Log Image log from AREX well, Cinco Terry B1601. Core photo from AREX well, Baker A112.

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Slide 25 Organic material Quartz and carbonate materials Storage space for oil and gas in Wolfcamp Shale - cont. Organic material in shale is not only a source for hydrocarbon generation, but also a "storage space" for gas to be adsorbed on their surface areas. 72.1 scf / ton Total gas content from canister desorption of Baker A112 2.24% - 7.24% TOC for Baker A112 October 18, 2010 Slide 25 Oil and Gas are stored in 3 forms in shale Matrix pore space Fractures Adsorption

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Hydrocarbon pathway to wellbore Slide 26 W E Ellenburger Canyon Wolfcamp Proximity to Ouachita-Marathon thrust belt and high concentration of carbonate and quartz minerals provide favorable conditions for fracture development at Wolfcamp level 4,000' 5,000' 6,000' 7,000' 8,000' 9,000' 10,000' Canyon Ellenburger Wolfcamp Faults Depth (feet) likely high fracture density areas Fossil fragments Quartz, carbonate, and fossils October 18, 2010 Slide 26 AREX 3-D Seismic

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Wolfcamp Shale components Slide 27 (CHART) Average Wolfcamp Shale components based on petrophysical analyses and core data from AREX Baker A112 October 18, 2010 Slide 27

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Regional correlation Slide 28 University 40-13 1H Baker A 112 Bailey 310 ~12.5 miles 'A A' ~12.8 miles SW Irion Co Cinco Terry Ozona NE October 18, 2010 Slide 28 Dean 6,100 6,200 6,300 6,400 6,500 6,600 6,700 6,800 6,900 7,000 7,100 5,500 5,600 5,700 5,800 5,900 6,000 6,100 6,200 6,300 6,400 6,500 4,900 5,000 ,5,100 5,200 5,300 5,400 5,500 5,600 5,700 5,800 5,900 Wolfcamp A Wolfcamp B Wolfcamp C 0 200 GR API 0.3 -0.1 NPHI 0.3 -0.1 DPHI 0 200 GR API 0.3 -0.1 NPHI 0.3 -0.1 DPHI 0 200 GR API 0.3 -0.1 NPHI 0.3 -0.1 DPHI

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Hydrocarbon column Slide 29 AREX Baker A 112 A' October 18, 2010 Slide 29 Hydrocarbon column > 2,500' in the Wolffork Clearfork A Clearfork B Clearfork C Hydrocarbon bearing zone

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30 Hydrocarbons in place estimate & potential vertical well recovery Slide 30 GIP (Gas in Place) / 640 Acre Reservoir Recovery Factor Well Spacing Potential Gas Recoverable / Well B scf % Acre Mcf Wolfcamp 164 10% 10 256,737 Recovery Factor Well Spacing MM Bbl % Acre Bbl Clearfork 56.0 3% 10 26,267 Dean 6.8 3% 10 3,185 Wolfcamp 91.5 3% 10 42,874 Recovery Factor Well Spacing Potential Hydrocarbons Recoverable / Well MMBoe % Acre Boe Wolfcamp 118.9 See Above 10 85,664 Wolfcamp, Dean 125.6 See Above 10 88,849 Wolfcamp, Dean, Clearfork 181.7 See Above 10 115,116 Formation OIL EQUIVALENT Formation GAS OIL Formation October 18, 2010 Slide 30 Vertical well Notes: The hydrocarbons in place estimate is based on petrophysical analyses and whole core data from Baker A112 in Cinco Terry. Recovery factors and well spacing are estimated by comparing key attributes of the Wolfcamp Shale with other producing commercial shale oil plays. Actual recovery factors and drainage results will vary. Oil equivalent is calculated using a 6 to 1 ratio. Hydrocarbons in Place / 640 Acre Reservoir OIP (Oil in Place) / 640 Acre Reservoir Potential Oil Recoverable / Well

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31 Slide 31 October 18, 2010 Slide 31 Horizontal well GIP / 640 Acre Reservoir Recovery Factor Well Spacing B scf % Acre Bcf Wolfcamp 164 10% 40 1.03 OIP / 640 Acre Reservoir Recovery Factor Well Spacing MM Bbl % Acre Bbl Wolfcamp 91.5 3% 40 171,497 Hydrocarbons In Place / 640 Acre Reservoir Recovery Factor Well Spacing MMBOE See Above Acre Boe Wolfcamp 118.9 See Above 40 342,655 GAS Formation OIL Formation Formation Hydrocarbons in place estimate & potential horizontal well recovery OIL EQUIVALENT Potential Gas Recoverable / Well Potential Hydrocarbons Recoverable / Well Potential Oil Recoverable / Well Notes: The hydrocarbons in place estimate is based on petrophysical analyses and whole core data from Baker A112 in Cinco Terry. Recovery factors and well spacing are estimated by comparing key attributes of the Wolfcamp Shale with other producing commercial shale oil plays. Actual recovery factors and drainage results will vary. Oil equivalent is calculated using a 6 to 1 ratio.

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AREX pilot program - summary of results Slide 32 October 18, 2010 Slide 32 Objectives Confirm hydrocarbons exist Determine fracability associated with pay zones Understand optimal perforations, fracing stages, fluids and proppants Results and takeaways All four pilot wells became producers with reasonable IPs Need to modify frac design to reactivate and/or create additional fractures and access additional rock volumes to improve IPs and EURs Planned Actual Oil (bbls) NGL (bbls) Gas (mcf) BOE (bbls) 1 Cinco Terry A 807 4 1 12,685 337,984 5.6 3.0 18.2 11.6 Screened out on 2nd stage. 2 University 42-15-2 3 3 16,236 492,000 34.0 10.0 60.0 54.0 3 Bailey 315 5 5 27,092 845,000 10 13.5 93.8 39.1 Working on possible mechanical issues. 4 University 42-23-12 1 1 2,072 89,875 14 4.6 28.14 23.3 12' of perforation and commingled with Canyon. Comments Fracing Stages Pilot Wells IP Fluids (bbls) Proppants (lbs)

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Wolfcamp vertical recompletion October 18, 2010 Slide 33 Modeled after AREX University 42-15 2 Initial Estimated Production Rate 54 BOEPD (Gas=10 BOE, NGL=10 BOE, Oil=34 BO)

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Wolffork vertical recompletion profile October 18, 2010 Slide 34 Initial Estimated Production Rate 89 BOEPD (Gas=16 BOE, NGL=16 BOE, Oil=56 BO)

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Canyon-Wolffork vertical new drill profile October 18, 2010 Slide 35 Initial Estimated Production Rate 144 BOEPD (Gas=52 BOE, NGL=51 BOE, Oil=53 BO)

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Vertical vs. horizontal development Slide 36 Vertical Horizontal Eagle Ford 49,500 323,813 6.5x Niobrara 40,000 290,000 7.3x Wolfcamp 54,449 353,600 6.5x Well EUR (Bbls) Oil Shale Play Potential Uplift October 18, 2010 Slide 36 Enhancing the value of shale oil plays Notes: Eagle Ford and Niobrara well EURs from industry publications. Wolfcamp well EUR is based on AREX estimates.

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Wolfcamp horizontal October 18, 2010 Slide 37 Modeled after University 40-13 1H Initial Estimated Production Rate 163 BOEPD (Gas=37 BOE, NGL=40 BOE, Oil=86 BO)

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October 18, 2010 Slide 38 Note: Wolffork economics based on current NYMEX strip. Wolffork economics summary (estimated)

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October 18, 2010 Slide 39 Wolfcamp recompletion - IRR sensitivity Wolffork recompletion - IRR sensitivity Canyon Wolffork new drill - IRR sensitivity Wolfcamp horizontal - IRR sensitivity Further opportunity for improvement on EURs and well costs Note: Wolffork economics based on current NYMEX strip. Wolffork economics (estimated)

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Oil shale play comparison Slide 40 October 18, 2010 Slide 40 How does the Wolffork play stack up against other commercial shale oil plays? *Density porosity ranges from 8% to 15%. Notes: The shale rock property (SRP) data for Avalon, Barnett, Eagle Ford and Niobrara are from industry publications. The SRP data for Wolffork are based on AREX Baker A 112 whole core.

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Technical evaluation derisks Wolffork play concept Slide 41 Hydrocarbon generating potential TOC R0 - Tmax - TAI Shale Rock Properties Lithology - Mineralogy Hydrocarbons in Place Technical Limit Commercial Limit Thermal maturity for hydrocarbon generation Storage capacity Fracability - shale response to fracing stimulation Well spacing, performance, recovery Play boundary, leasing strategy D&C cost, technology & commodity price Execution Reserves, production optimization, NPV & IRR Natural Fracture Hydrocarbon pathway to wellbore October 18, 2010 Slide 41 Creating value through detailed technical evaluation

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Key takeaways ....a world class source rock with significant hydrocarbon-generating potential ....thermally matured and currently located in peak oil generation and early gas generation window October 18, 2010 Slide 42 The WOLFCAMP Is ....storage space, including matrix porosity, natural fractures, and organic materials ....core porosity of 4%-11% and density porosity of 8%-15% ....mineral compositions and lithology similar to the Wolfberry and Eagle Ford Shale ....high density of natural fractures observed in whole cores, image logs and 3-D seismic data ....significant estimated oil and gas in place with 119 to 182 MMBoe per 640 acres under AREX's 93,065 net acres - a small increase in recovery factor could impact well recovery and economics significantly ....results from pilot wells in Southern Midland Basin that are encouraging The WOLFCAMP Has

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AREX's next steps - 2010 October 18, 2010 Slide 43 What's next? Continue to delineate the Wolffork trend across AREX's acreage and refine the completion practice: Wolfcamp horizontal Cinco Terry "M" 901-H Expected spud end of October 2010 and completion 1Q'11 Wolfcamp recompletion Cinco Terry 1601 Expected early November 2010 2010 Estimated capital expenditures Preliminary and unaudited($ in thousands) Capital Expenditures Capital Expenditures 2010 Initial capital expenditure budget $ 53,000 Additional lease acquisitions 9,000 Additional Wolffork G&G 1,000 Total 2010 estimated capital expenditures* $ 63,000 Develop 2011 capital and drilling program Continue to monitor industry activity in Southern Midland Basin Wolfcamp play Continue to add prospective acreage *Excludes additional acreage or asset acquisitions. Wolffork recompletions 2 recompletions in Ozona Northeast Finalizing locations Canyon-Wolffork new drill Baker C 1201 Completion expected mid-late November 2010

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Liquidity October 18, 2010 Slide 44 ($ in thousands) 9/30/2010Actual 9/30/2010Actual 9/30/2010Pro Forma for Borrowing Base Increase 9/30/2010Pro Forma for Borrowing Base Increase Cash and cash equivalents $ 417 $ 417 Borrowings under credit facility $ 51,069 $ 51,069 Total credit facility 115,000 150,000 % Available 56% 66% Unused letters of credit 350 350 Liquidity $ 63,998 $ 98,998 Liquidity as of 9/30/2010 Borrowing base will increase by $35 mm to $150 mm by November 2010

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Q&A