EXHIBIT 99.1

Howard Weil 39th Annual Energy Conference March 28-31, 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, 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 and acreage as of 3/1/2011, and includes estimated proved reserves and net acres from 38% WI acquisition in February 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 $31.73 per share on 3/25/2011, plus net debt as of 2/28/2011. Enterprise value $960 MM 4.7 MBoe/d Q4 2010 production 59.7 MMBoe proved reserves 96% Permian Basin 52% Oil & NGLs 52% Proved developed 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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Key investor highlights Concentrated geographic footprint focused on West Texas Midland Basin oil/liquids rich plays 133,000+ net, primarily contiguous acres, 100% operated More than 525 wells drilled by Approach since 2004, with a 93%+ success rate Established basin infrastructure Strong growth track record at competitive costs Reserve and production CAGR since 2004 of 31% and 46%, respectively Low-cost operator with best-in-class F&D and lifting costs Significant growth potential from drilling inventory supported by extensive technical evaluation 1,070 potential Canyon Wolffork new drills 1,230 potential horizontal Wolfcamp locations 480 potential behind pipe Wolffork recompletion opportunities Strong balance sheet to execute development plan $85.1 million of liquidity at 2/28/2011 43% of 2011 natural gas production hedged at $4.86/MMBtu Significant potential upside from future development of drilling inventory Note: Liquidity calculation provided in appendix. Slide 4

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2010-11 Highlights 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 Midland 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 Midland Basin In October 2010, acquired 10% working interest in Cinco Terry In February 2011, acquired remaining 38% working interest in Cinco Terry - estimated proved reserves 9 MMBoe Average WI in the Midland Basin now approximately 100% Proved reserves increased 39% to 50.7 MMBoe at YE 2010 Oil and NGL reserves increased >200% to 25.7 MMBbls Reserve mix 51% oil and NGLs and 49% natural gas at YE 2010 2010 All-in F&D cost $5.70/Boe 2010 All-in production replacement 1,014% Slide 5 Notes: All-in F&D costs and reserve replacement ratio calculations provided in appendix.

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Strong track record of reserve and production growth October 12, 2010 Slide 6 Note: 2011E production and production mix based on the midpoint of production guidance. Reserve growth Production growth Proved reserves (MMBoe) Production (MBoe/d) Slide 6 (CHART) 2004-2010 CAGR: 31% (CHART) 2004-2011E CAGR: 46% 51% Oil & NGLs 55% Oil & NGLs

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(CHART) (CHART) 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 (CHART) (CHART)

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Low-cost operator across crude-oil weighted peers October 12, 2010 Slide 8 Notes: Peers include BRY, BEXP, CXO, KOG, NOG, OAS, PETD, and SD. Based on public filings. Lifting costs defined as lease operating expense plus taxes other than income and gathering and transportation expense. See "F&D costs reconciliation" slide in appendix for reconciliation of 3-year average F&D costs for AREX. 4Q 2010 lifting costs ($/Boe) 3-year average F&D costs ($/Boe) (CHART) (CHART) Slide 8 $7.94 $8.95

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(CHART) 2011 Capital budget - $220 MM October 12, 2010 Slide 9 2011 Plan 2011 capital budget of $220 MM $130 MM for drilling and recompletion projects in Project Pangea $76 MM for February 2011 38% WI acquisition $14 MM for lease extensions and renewals $220 MM does not include additional lease or property acquisitions Note: Production growth and production mix based on midpoint of 2011 production guidance. (CHART) (CHART) 4.3 6.5 Production (MBoe/d) 2010 2011E Slide 9 69% Gas 31% Oil & NGLs 45% Gas 55% Oil & NGLs Oil & NGL Expected Production Growth in 2011 Targeting 50%+ Production Growth in 2011

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Overview of AREX's Midland Basin assets Recent acreage acquisitions increased Midland Basin acreage position to 153,000 gross (133,000 net) acres Project Pangea AREX operated with average ~100% WI, ~78%NRI 57.3 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 shale resource play located above traditional Canyon, Strawn and Ellenburger targets 1,070 potential Canyon Wolffork new drills 1,230 potential horizontal Wolfcamp locations 480 potential Wolffork recompletions Slide 10 Proved reserves: 57.3 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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Wolffork pilot program - Phase II October 12, 2010 Slide 11 Slide 11 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 2 62.4 29.7 6.5 37.8 42.5 Pilot E Recompletion 3 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 Completed 1st horizontal well mid-March 2011 5,377' lateral 15 stages Note: Average vertical Wolfberry well IP based on internal Company studies.

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2011 Pilot program - What are our objectives? October 12, 2010 Slide 12 2011 Pilot program objectives Delineate Wolffork oil shale play 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 12

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Wolffork Oil Shale Resource Play Midland Basin

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Slide 14 AREX acreage is favorably located in Southern Midland Basin Slide 14 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 15 Recent activity in Southern Midland Basin Slide 15

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Wolffork play recognition Slide 16 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 or show data 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 Why didn't others recognize the play? AREX Slide 16

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Structural cross-section across Big Lake Fault Slide 17 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 Slide 17

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AREX Wolfcamp producers and shows Slide 18 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 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 Slide 18

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AREX shale play evaluation process Slide 19 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 Creating value through detailed technical evaluation Slide 19

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Creating value through detailed technical evaluation of Wolfcamp shale Slide 20 TOC for Wolfcamp Shale from whole core of Baker A112: World class source rock in oil window Thermal Maturity 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 Baker A112 Wolfcamp R0 ~0.95-0.97 Richness Good - Excellent Fair TOC (%) 2-10 1-2 <1 Poor 2.24% - 7.24% Oil & gas storage criteria for shales: Matrix pore space Fractures Adsorption Significant oil & gas storage space Wolfcamp shale: Natural Fractures Organic material Quartz and carbonate materials Core porosity % Core porosity for Baker A112 Fractures Absorption Slide 20

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Creating value through detailed technical evaluation of Wolfcamp shale (cont'd) Slide 21 Hydrocarbon pathway to wellbore Wolfcamp shale components 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' Depth (feet) Canyon Ellenburger Wolfcamp Faults likely high fracture density areas Fossil fragments Quartz, carbonate, and fossils (CHART) Average Wolfcamp Shale components based on petrophysical analyses and core data from AREX Baker A112 Slide 21

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Regional correlation Slide 22 University 40-13 1H Baker A 112 Bailey 310 ~12.5 miles ~12.8 miles SW Irion Co Cinco Terry Ozona NE 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 Slide 22

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Over 2,500 feet of gross pay in the Wolffork Slide 23 AREX Baker A 112 Clearfork A Clearfork B Clearfork C Hydrocarbon bearing zone Slide 23

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24 Hydrocarbons in place estimate & potential well recovery Slide 24 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. Slide 24 Horizontal well Hydrocarbons in Place / 640 Acre Reservoir Recovery Factor Well Spacing Potential Hydrocarbon Recoverable / Well MMBOE Acre Boe Wolfcamp 118.9 10 85,664 Wolfcamp, Dean 125.6 10 88,849 Wolfcamp, Dean, Clearfork 181.7 10 115,116 Oil EQUIVALENT Formation Gas - 10% Oil - 3% Hydrocarbons in Place / 640 Acre Reservoir Recovery Factor Well Spacing Potential Hydrocarbon Recoverable / Well MMBOE Acre Boe Wolfcamp 118.85 40 342,655 Oil EQUIVALENT Formation Gas - 10% Oil - 3%

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Wolfcamp horizontal (EOG 40-13-1H) Technical analysis is supported by early drilling and recompletion results Wolfcamp vertical recompletion (AREX U42-15-2) 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. Slide 25 Modeled after Approach U45-15-2 well Initial Potential 54 BOE (Gas=10 BOE, NGL's=10 BOE, Oil=34 BO

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Note: Wolffork economics based on NYMEX strip in October 2010, estimated F&D cost calculated as D&C cost divided by total well EUR. Wolffork economics summary (estimated) Approach's technical evaluation yields Original Oil & Gas in Place resource per section of 118 MMboe for Wolfcamp shale and 63 MMboe for Dean/Clearfork EUR estimates support conservative recovery assumptions of 10% for gas and 3% for oil Optimized drilling and completion efforts could improve recovery factors, increasing EUR per well 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. Slide 26 Oil (Bbl) NGL (Bbl) Gas (Mcf) Total (BOE) Wolfcamp Recompletion 21,910 16,592 100,680 55,282 550,000 19% 9.95 Wolffork Recompletion 40,950 24,800 145,702 90,034 850,000 25% 9.44 480 Canyon Wolffork New Drill 75,420 63,170 390,648 203,698 1,700,000 32% 8.35 1,100 Wolfcamp Horizontal (Development Well) 191,032 79,512 498,336 353,600 3,500,000 30% 9.90 1,230 Potential Drilling Locations F&D Cost per BOE ($) IRR Type Well EUR D&C Cost ($)

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Wolffork recompletion - IRR sensitivity Canyon Wolffork new drill - IRR sensitivity Wolfcamp horizontal - IRR sensitivity Further opportunity for improvement on EURs and well costs Wolffork economics (estimated) Potential drilling locations: 1,230 Potential recompletion locations: 480 Potential drilling locations: 1,070 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. Slide 27

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Oil shale play comparison Slide 28 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 Bakken, Barnett, Eagle Ford and Niobrara are from industry publications. The SRP data for Wolffork are based on AREX Baker A 112 whole core. Slide 28

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Technical evaluation derisks Wolffork play concept Slide 29 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 Creating value through detailed technical evaluation Slide 29

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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 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 133,000 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 Slide 30

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Appendix

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2010 Operating and financial highlights October 12, 2010 Slide 32 2010 Highlights (in thousands, except per-share metrics) Year EndedDecember 31, Year EndedDecember 31, Year EndedDecember 31, Year EndedDecember 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 % Note: See "Adjusted Net Income" and "EBITDAX" reconciliation slides in appendix for reconciliation of adjusted net income and EBITDAX, respectively. Slide 32

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2011 Guidance Production and operating and expenses guidance Slide 33 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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Liquidity (in thousands) 2/28/2011 2/28/2011 Borrowing base $ 150,000 Cash and cash equivalents 2,422 Outstanding letters of credit (350) Long-term debt (67,000) Liquidity $ 85,072 Liquidity as of 2/28/2011 Note: preliminary and unaudited. Slide 34 55% of borrowing base available

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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 included in our Annual Report on Form 10-K to be filed with the SEC on March 11, 2011. Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods before the periods in which related increases in reserves are recorded and development costs may be recorded in periods after the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases (or decreases) in reserves independent of the related costs of such increases. 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 35

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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 36 (in thousands, except per-share amounts) Year EndedDecember 31, Year EndedDecember 31, Year EndedDecember 31, Year EndedDecember 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 37 (in thousands, except per-share amounts) Year EndedDecember 31, Year EndedDecember 31, Year EndedDecember 31, Year EndedDecember 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