Exhibit 99.1

KeyBanc Capital Markets Permian Basin Bus Tour January 19, 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: Acreage as of 11/8/2010. Net acreage may change subject to partner elections on recent acreage acquisitions. 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 $25.29 per share on 1/14/2010, less cash as of 12/31/2010. Enterprise value (EV) ($MM) $690 Proved reserves @ 6/30/10 (MMBoe) 46.4 EV per proved Boe ($/Boe) $14.89 4.5 MBoe/d Q3 2010 production 46.4 MMBoe proved reserves 95% Permian Basin 50% Oil & NGLs 48% Proved developed No reserves currently booked for Wolffork development 337,339 gross (230,243 net) acres 98,098 net acres in the Permian Basin 2,900 drilling and recompletion opportunities Areas of operation AREX highlights Slide 3

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Key investor highlights Concentrated geographic footprint focused on West Texas Permian Basin oil/liquids rich plays 98,000+ net, primarily contiguous acres, 100% operated More than 400 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 32% and 41% respectively Low-cost operator with best-in-class F&D and lifting costs Significant growth potential from drilling inventory supported by extensive technical evaluation 1,100 Canyon Wolffork new drills 1,230 horizontal Wolfcamp locations 480 behind pipe Wolffork recompletion opportunities Strong balance sheet to execute development plan 50% of 2011 natural gas production hedged at $4.86 per MMBtu $173.1 million of liquidity at 12/31/2010 Compelling valuation with significant additional upside from future development of drilling inventory Notes: Liquidity calculation provided on slide 26. Slide 4

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Strong track record of reserve and production growth October 12, 2010 Slide 5 Note: 2010E and 2011E production based on the midpoint of production guidance, or 1.6 MMBoe and 1.9 MMBoe, respectively. 2011 production estimated to be 53% oil and NGLs. 4% Oil & NGLs 6% Oil & NGLs 6% Oil & NGLs 11% Oil & NGLs 18% Oil & NGLs 23% Oil & NGLs 50% Oil & NGLs 2004-Mid Year 2010 CAGR: 32% 2004-2011E CAGR: 41% Reserve growth Production growth Proved reserves (MMBoe) Production (MBoe/d) Slide 5

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Low-cost operator across crude-oil weighted peers October 12, 2010 Slide 6 Notes: 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 F&D costs. 3Q 2010 lifting costs ($/Boe) 3-year average F&D costs ($/Boe) Slide 6

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3Q 2010 operating and financial highlights October 12, 2010 Slide 7 3Q 2010 highlights Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, Variance Variance Variance 2010 2010 2009 2009 (%) (%) (%) Revenues $ 14,916 $ 8,787 ? 70 % Net income $ 2,087 $ (3,144) ? 166 % Net income (loss) per diluted share $ 0.10 $ (0.15) ? 166 % Adjusted net income (non-GAAP) $ 2,293 $ 1,089 ? 111 % Adjusted net income per diluted share $ 0.11 $ 0.05 ? 120 % EBITDAX (non-GAAP) $ 11,628 $ 8,886 ? 31 % EBITDAX per diluted share $ 0.54 $ 0.42 ? 29 % Realized price ($/Boe) (excluding commodity derivatives) $ 35.65 $ 26.32 ? 35 % Production (MBoe/d) 4.5 3.6 ? 25 % Notes: See "Adjusted Net Income" and "EBITDAX" reconciliation slides in appendix for reconciliation of adjusted net income and EBITDAX, respectively. Slide 7

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2011 Capital budget - $100 MM October 12, 2010 Slide 8 2011 Plan 2011 capital budget of $100 million Substantially all of 2011 budget allocated to Project Pangea: One rig to drill ~11 gross (7 net) horizontal wells targeting Wolfcamp Shale One rig to drill ~19 gross (19 net) vertical wells targeting Wolffork and Canyon Sands One rig to drill ~26 gross (16 net) 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 $7 million for lease extensions and renewals No amounts currently included for additional lease or property acquisitions Note: Production growth based on midpoints of 2010 and 2011 production guidance. 4.3 5.3 Production (MBoe/d) 2010E 2011E Targeting 20%+ Production Growth Oil & NGL Expected Production Growth in 2011 Slide 8

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2011 Plan - What are our objectives? October 12, 2010 Slide 9 2011 Plan 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 9

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Overview of AREX's Permian Basin assets Recent acreage acquisitions connect Ozona NE and Cinco Terry fields into 98,098 primarily contiguous net acres with multiple pay zones Current formation targets include: Clearfork, Wolfcamp Shale, Canyon Sands, Strawn and Ellenburger Ozona NE / Cinco Terry Legacy asset with significant remaining development potential AREX operated with average ~88% WI, ~68%NRI 43.9 MMBoe proved reserves, 4.5 MBoe/d production 1,100 identified locations targeting Canyon Sands and deeper zones Overview Project Pangea - Proved reserves 43.9 MMBoe Significant upside potential in Wolffork play Emerging oil resource play located above traditional Canyon, Strawn and Ellenburger targets 480 Wolffork recompletions 1,230 horizontal Wolfcamp locations 1,100 Canyon Wolffork new drills Dean Clearfork /Spraberry Wolfcamp Cisco Canyon Ellenburger Strawn San Andres Grayburg Stratigraphic Unit AREX - New Acreage El Paso's Sept. 2010 University of Texas lease acquisition at $1,460/acre 2500' gross pay Southern Midland Basin ValVerde Basin / Ozona Arch AREX - New Acreage Slide 10

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Slide 11 AREX acreage is favorably located in Southern Midland Basin Wolfberry Well ~28 miles Project Pangea Play activities during 2007-Present Midland 6) Howard Upton 7) Glasscock Martin 8) Reagan Ector 9) Irion Andrew 10) Crockett Wolffork Play Wolfberry Play Wolfberry Play Slide 11

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Industry activity in Southern Midland Basin Slide 12 Recent activity in Southern Midland Basin Slide 12

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Wolffork play recognition Slide 13 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 13

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AREX Wolfcamp producers and shows Slide 14 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 14

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AREX shale play evaluation process Slide 15 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 15

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Creating value through detailed technical evaluation of Wolfcamp shale Slide 16 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 16

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Creating value through detailed technical evaluation of Wolfcamp shale (cont'd) Slide 17 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 Average Wolfcamp Shale components based on petrophysical analyses and core data from AREX Baker A112 Slide 17

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Regional correlation Slide 18 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 18

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Over 2,500 feet of gross pay in the Wolffork Slide 19 AREX Baker A 112 Clearfork A Clearfork B Clearfork C Hydrocarbon bearing zone Slide 19

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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 20

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Note: Wolffork economics based on NYMEX strip, 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 21

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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) Drilling locations: 1,230 Recompletion locations: 480 Drilling locations: 1,100 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 22

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Oil shale play comparison Slide 23 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 23

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Technical evaluation derisks Wolffork play concept Slide 24 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 24

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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 98,098 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 25

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Liquidity (in thousands) 12/31/2010 12/31/2010 Cash and cash equivalents $ 23.5 Borrowings under credit facility $ 0.0 Total credit facility 150.0 % Available 100% Unused letters of credit (0.4) Liquidity $ 173.1 Liquidity as of 12/31/2010 Borrowing base increased by $35 MM to $150 MM in October 2010 Notes: preliminary and unaudited. Slide 26

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Appendix

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Structural cross-section across Big Lake Fault Slide 28 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 28

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29 Hydrocarbons in place estimate & potential vertical well recovery Slide 29 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 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 Slide 29

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30 Slide 30 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. Slide 30

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2011 Guidance 2011 Production and expenses guidance Slide 31

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F&D 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 12, 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 32

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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 33

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EBITDAX reconciliation (unaudited) We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss (gain) on commodity derivatives, (5) interest expense and (6) income taxes. EBITDAX is not a measure of net income or cash flow as determined by GAAP. 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 34