Exhibit 99.2

Company Update 2010 Results and Highlights March 8, 2011

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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 production and operating expenses guidance 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," "target," "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 for the year ended December 31, 2009, and our Quarterly reports on Form 10-Q for the periods ended June 30, 2010 and September 30, 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 Securities and Exchange Commission ("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" 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, lease 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. Estimated EURs, related oil and gas in place, recovery factors and well costs represent Company-generated estimates based on evaluation of petrophysical analysis, core data and well logs, well performance from limited drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are presented as hypothetical recoveries if assumptions and estimates regarding recoverable hydrocarbons, OGIP, recovery factors and costs prove correct. The Company has very limited production experience with these projects, and accordingly, such estimates may change significantly as results from more wells are evaluated. Estimates of EURs and OGIP do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to include in SEC filings. IRR estimates assume NYMEX forward-curve oil and gas pricing and Company-generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include land, seismic or G&A costs Cautionary statements regarding oil and gas quantities

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Company overview Notes: Proved reserves as of 12/31/2010 ; acreage as of 3/1/2011. All Boe and Mcfe calculations are based on a 6 to 1 conversion ratio. Enterprise value is equal to market capitalization using the closing price of $32.55 per share on 2/28/2011, less cash as of 12/31/2010. PV-10 reconciliation provided in appendix. Enterprise value (EV) ($MM) $895 Proved reserves (MMBoe) 50.7 EV per proved Boe ($/Boe) $17.65 4.7 MBoe/d Q4 2010 production 50.7 MMBoe proved reserves 95% Permian Basin 51% Oil & NGLs 51% Proved developed PV-10 $325.8 MM No proved reserves currently booked for Wolffork development 153,000 gross (133,000 net) acres in the Permian Basin 2,780+ potential drilling and recompletion opportunities in the Permian Basin Areas of operation AREX highlights Slide 3

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2010 Accomplishments Wolffork oil shale resource play Three stacked pay zones, the Clearfork, Dean and Wolfcamp Shale > 2,500 feet of gross pay Wolffork possible reserves 38.7 MMBoe Expanded core acreage position in the Permian Basin During 2010, AREX added approximately 34,800 net acres to Project Pangea As of March 1, 2011, Permian acreage position covers 133,000 net acres, 100% operated Increased working interest in the Permian Basin In October 2010, acquired 10% working interest in Cinco Terry In February 2011, acquired remaining 38% working interest in Cinco Terry Average WI in the Permian Basin now approximately 100% Proved reserves increased 39% to 50.7 MMBoe Oil and NGL reserves increased >200% to 25.7 MMBbls Reserve mix now 51% oil and NGLs and 49% natural gas Slide 4

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2010 operating and financial highlights October 12, 2010 Slide 5 2010 Highlights Year Ended December 31, Year Ended December 31, Year Ended December 31, Year Ended December 31, Variance Variance Variance 2010 2010 2009 2009 (%) (%) (%) Revenues $ 57,581 $ 40,648 ? 42 % Net income (loss) $ 7,462 $ (5,229) ? 243 % Net income (loss) per diluted share $ 0.34 $ (0.25) ? 236 % Adjusted net income (non-GAAP) $ 8,673 $ 3,261 ? 166 % Adjusted net income per diluted share $ 0.39 $ 0.16 ? 144 % EBITDAX (non-GAAP) $ 43,026 $ 36,743 ? 17 % EBITDAX per diluted share $ 1.94 $ 1.75 ? 11 % Realized price ($/Boe) (excluding commodity derivatives) $ 37.00 $ 27.69 ? 34 % Production (MBoe/d) 4.3 4.0 ? 6 % Notes: See "Adjusted Net Income" and "EBITDAX" reconciliation slides in appendix for reconciliation of adjusted net income and EBITDAX, respectively. Slide 5

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2010 Proved reserves Slide 6 Proved reserves ? 39% to 50.7 MMBoe Oil & NGL reserves ? 204% to 25.7 MMBbls Reserve mix 51% oil and NGLs and 49% natural gas Proved developed reserves ? 66% to 25.8 MMBoe Reserve mix 51% proved developed 49% proved undeveloped PV-10 ? 153% to $325.8 mm All-in finding and development cost $5.70/Boe All-in reserve replacement 1,014% Reserves highlights Notes: All-in F&D costs and reserve replacement calculations provided in appendix. 2004-2010 CAGR: 31% Reserve growth Proved reserves (MMBoe) 4% Oil & NGLs 6% Oil & NGLs 6% Oil & NGLs 11% Oil & NGLs 18% Oil & NGLs 23% Oil & NGLs 51% Oil & NGLs

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Well-balanced reserve mix September 24, 2010 Slide 7 23% Oil & NGLs 77% Natural Gas 43% Proved Developed 57% Proved Undeveloped 51% Proved Developed 49% Proved Undeveloped 51% Oil & NGLs 49% Natural Gas Reserve mix at December 31, 2009 Reserve mix at December 31, 2010 Slide 7

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2010 Proved reserves Slide 8 49% PUD Reserves summary 51% PDP Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Total (MBoe) Proved developed Permian Basin 2,146 11,193 73,208 25,540 East Texas Basin ^ ^ 1,531 255 Proved undeveloped Permian Basin 2,805 9,506 62,555 22,737 East Texas Basin ^ ^ 13,095 2,183 Total proved 4,951 20,699 150,389 50,715 Probable Permian Basin 1,911 7,471 49,338 17,605 East Texas Basin ^ ^ 6,320 1,053 Possible Permian Basin 17,134 16,034 98,314 49,554 East Texas Basin ^ ^ 2,108 351 Grand total 23,996 44,204 306,469 119,278 Possible reserve category includes 38.7 MMBoe attributable to the Wolffork oil shale resource play

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Q4'10 / FY'10 Production and operations Slide 9 Q4'10 production ? 31% to 4.7 MBoe/d 6th consecutive quarter for production growth Oil & NGL production ? 69% to 162 MBbls Drilled 19 gross (11.7 net) wells FY'10 production ? 6% to 4.3 MBoe/d Oil & NGL production ? 22% to 508 MBbls Drilled 91 gross (56.2 net) wells, with a 100% success rate Targeting 50%+ production growth in 2011 2011 Production estimated to be 55% oil and NGLs Production and operations highlights 2004-2011E CAGR: 46% Production (MBoe/d) 3% Oil & NGLs 7% Oil & NGLs 7% Oil & NGLs 9% Oil & NGLs Production growth Note: 2011E production based on the midpoint of production guidance, or 2.4 MMBoe. 2011 production estimated to be 55% oil and NGLs. 55% Oil & NGLs

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Wolffork pilot program - Phase II October 12, 2010 Slide 1 2011 Objectives Delineate Wolffork across Project Pangea with a combination of vertical, horizontal and recompletion projects Improve initial production rates by refining our perforation and fracture stimulation strategy Advance understanding of optimal well spacing and hydrocarbon recovery Improve cost structure Measure progress in the aggregate, not well-by-well, day-by-day Slide 10 Stabilized IP Stabilized IP Stabilized IP Stabilized IP Vertical Pilot Wells Pilot Type No. of Frac Stages Max IP (Boe/d) Oil (Bbls) NGLs (BBls) Natural Gas (MMcf) Total (Boe/d) Pilot A New Drill 5 140.8 25.0 43.0 250.0 109.7 Pilot B New Drill 5 102.3 26.0 29.0 168.0 83.0 Pilot C New Drill 5 124.2 39.0 19.0 110.0 76.3 Pilot D Recompletion 3 62.4 29.7 6.5 37.8 42.5 Pilot E Recompletion 2 24.3 13.0 4.0 24.0 21.0 Recent pilot well results Pilot wells A, B and C completed in the Canyon and Wolffork with five frac stages Pilot wells D and E recompleted in the Wolfcamp zone with two and three frac stages, respectively Average vertical Wolfberry well IP near/north of Crockett Co ranges from 50 to 75 Boe/d Typical Wolfberry frac includes 7 to 8 stages Next up - complete 1st horizontal well mid-March 2011

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Working interest acquisition October 12, 2010 Slide 11 Acquisition highlights $76 million purchase price 9.0 MMBoe estimated proved reserves 61% oil and NGLs, 39% gas 61% PDP 4.7 MMBoe estimated unproved reserves Estimates of proved and unproved reserves do not include reserve potential for the Wolffork oil shale resource play 1.4 MBoe/d current production 19,800 net acres Increases AREX's position in the Permian Basin to 133,000 net acres AREX's WI and NRI in Permian acreage position now approximately 100% and 78% Slide 11

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2011 Capital budget - $220 MM October 12, 2010 Slide 12 2011 Plan 2011 capital budget of $220 MM Substantially all of 2011 budget allocated to Project Pangea: One rig to drill 11 horizontal wells targeting Wolfcamp Shale One rig to drill 19 vertical wells targeting Wolffork and Canyon Sands One rig to drill 26 vertical wells targeting Canyon Sands (expected to recomplete up hole in Wolffork in 2012) One workover rig to recomplete 10 wells in Wolffork Budget includes $90 MM for working interest acquisition, lease extensions and renewals $220 MM does not include additional lease or property acquisitions Note: Production growth based on midpoint of 2011 production guidance. 4.3 6.5 Production (MBoe/d) 2010E 2011E Targeting 50%+ Production Growth Oil & NGL Expected Production Growth in 2011 Slide 12

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2011 Guidance Production and operating and expenses guidance Slide 13 2011 Guidance 2011 Guidance Production Total (MBoe) 2,300 - 2,450 Percent oil and NGLs 55% Operating costs and expenses (per Boe) Lease operating $ 4.25 - 5.50 Severance and production taxes $ 2.00 - 2.30 Exploration $ 4.00 - 5.00 General and administrative $ 5.00 - 6.00 Depletion, depreciation and amortization $ 12.00 - 15.00 Capital expenditures (in millions) Approximately $220 Targeting 50%+ Y/Y production growth

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Overview of AREX's Permian Basin assets Recent acreage acquisitions increase Permian acreage position to 153,000 gross (133,000 net) acres Project Pangea AREX operated with average ~100% WI, ~78%NRI 48.4 MMBoe proved reserves 4.7 MBoe/d Q4'10 production 2,780+ potential drilling and recompletion locations targeting Wolffork, Canyon Sands and deeper zones Significant upside potential in Wolffork play Emerging oil resource play located above traditional Canyon, Strawn and Ellenburger targets 1,070 Canyon Wolffork new drills 1,230 horizontal Wolfcamp locations 480 Wolffork recompletions Slide 14 New Acreage Proved reserves: 48.4 MMBoe Net acres: 133,000 Project Pangea Dean Clearfork /Spraberry Wolfcamp Cisco Canyon Ellenburger Strawn San Andres Grayburg 2,500' gross pay Southern Midland Basin Val Verde Basin Ozona Arch Tight sand Target Carbonate Carbonate Shale Shale Wolffork Shale Stratigraphic units and current AREX drilling targets

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Slide 15 AREX acreage is favorably located in Southern Midland Basin Slide 15 Wolfberry Well ~28 miles Pangea West Wolffork Play Wolfberry Play Wolfberry Play Project Pangea

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Industry activity in Southern Midland Basin Slide 16 Recent activity in Southern Midland Basin Slide 16

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Appendix

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PV-10 Reconciliation (unaudited) (in thousands) 12/31/2010 12/31/2010 PV-10 $ 325,808 Less income taxes: Undiscounted future income taxes (282,628) 10% discount factor 161,052 Future discounted income taxes (121,576) Standardized measure of discounted future net cash flows $ 204,232 PV-10 as of 12/31/2010 Notes: preliminary and unaudited. Slide 18 The present value of our proved reserves, discounted at 10% ("PV-10"), was estimated at $325.8 million at December 31, 2010, and was calculated based on the first-of- the-month, twelve-month average prices for natural gas, oil and NGLs, of $4.38 per MMBtu of natural gas, $79.40 per Bbl of oil and $39.25 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.

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F&D costs reconciliation and reserve replacement ratio (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 Boe 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 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, 2010. 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 we use 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 reflects the reconciliation of our estimated finding and development costs to the information required by paragraphs 11 and 21 of ASC 932-235: Slide 19

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Adjusted net income reconciliation (unaudited) 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. Slide 20 (in thousands, except per-share amounts) Year Ended December 31, Year Ended December 31, Year Ended December 31, Year Ended December 31, 2010 2010 2009 2009 Net income (loss) $ 7,462 $ (5,229) Adjustments for certain non-cash items Impairment of unproved properties 2,622 2,964 Unrealized loss (gain) on commodity derivatives (788) 9,899 Related income tax effect (623) (4,373) Adjusted net income $ 8,673 $ 3,261 Adjusted net income per diluted share $ 0.39 $ 0.16

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EBITDAX reconciliation (unaudited) We define EBITDAX as net income, plus (1) exploration expense, (2) impairment of unproved properties, (3) depletion, depreciation and amortization expense, (4) share-based compensation expense, (5) unrealized (gain) loss 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. 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. Slide 21 (in thousands, except per-share amounts) Year Ended December 31, Year Ended December 31, Year Ended December 31, Year Ended December 31, 2010 2010 2009 2009 Net income (loss) $ 7,462 $ (5,229) Exploration 2,589 1,621 Impairment of unproved properties 2,622 2,964 Depletion, depreciation and amortization 22,224 24,660 Share-based compensation 2,628 1,826 Unrealized (gain) loss on commodity derivatives (788) 9,899 Interest expense, net 2,189 1,787 Income tax provision (benefit) 4,100 (785) EBITDAX $ 43,026 $ 36,743 EBITDAX per diluted share $ 1.94 $ 1.75