Exhibit 99.1

Company March 16, 2010 Presentation

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Forward-looking statements and cautionary statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of management regarding plans, strategies, objectives, anticipated financial and operating results of the Company, including as to the Company's drilling program, estimated reserves and drilling locations, hedging activities, capital expenditures and financial and operating guidance included in the presentation. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate and believed to be reasonable by management. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. In particular, careful consideration should be given to the cautionary statements and risk factors described in the Company's Annual Report on Form 10-K filed with the Securities and Exchange Commission ("SEC") on March 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 now 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," "EUR," "resource" reserves, reserve "potential," "upside" or 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. March 16, 2010 | 2

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AREX overview Core areas of operation(1) (1)As of December 31, 2009. (2)Based on March 9, 2010 closing price of $9.62 per share and 20.9 mm shares outstanding at December 31, 2009. (3)Net debt at December 31, 2009 was $29.6 mm. March 16, 2010 | 3 Exchange/Ticker Market cap $201.6 mm(2) Enterprise value $231.2 mm(3)

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AREX investment highlights High quality, long-lived asset base to ride price cycles Low risk, repeatable, multi-year drilling inventory of over 1,300 identified locations Strong balance sheet heading into 2010(1) Liquidity of $85.4 million Long-term debt-to-capital of 12.8% 2010 guidance midpoint of 25.1 MMcfe/d is a 15.7% increase in production over December 2009 production of 21.7 MMcfe/d Technically driven management team with a proven track record of unconventional resource exploration, evaluation and development Attractive valuation versus peers: EV per 2009 proved reserve ~$1.06/Mcfe(2) March 16, 2010 | 4 Proved reserves growth (Bcfe) Production growth (MMcfe/d) (1)See important disclosures regarding liquidity and long-term debt-to-capital on page 24. (2)Based on March 9, 2010 closing price of $9.62 per share and December 31, 2009 balance sheet and reported proved reserve estimates. (3)Pro forma for the November 14, 2007 acquisition of Neo Canyon Exploration, L.P.'s 30% working interest in Ozona Northeast, as if the acquisition occurred on January 1, 2007. (4)Pro forma for the Neo Canyon acquisition.

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2009 Financial and operational highlights March 16, 2010 | 5 (1)Finding and development costs, production replacement measures, EBITDAX, adjusted net income and liquidity are non-GAAP measures. Reconciliations and important disclosures regarding these measures can be found in the appendix. 2009 Highlights(1) 2009 2008

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2009 Reserves and unrisked potential Reserve overview(1) (1)Estimates of proved, probable and possible reserves at December 31, 2009 are based on an independent engineering report of our oil and gas properties prepared by DeGolyer and MacNaughton. Probable and possible reserves are unrisked and unbooked. (2)PV-10 is a non-GAAP measure. Reconciliations and important disclosure regarding PV-10 can be found on page 30. Category Oil/NGLs (MBbls) Gas (MMcf) Equivalent (MMcfe) March 16, 2010 | 6 Reserve sensitivity Price scenario MBbls MMcf MMcfe PV-10(2) Under the SEC's new reserve rules, 2009 estimated reserves are based on the first-of-the-month, 12-month average price for natural gas, oil and NGLs ($3.87/MMBtu, $61.04/Bbl of oil and $27.20/Bbl of NGLs) We also provide 2009 estimated reserves under the SEC's previous reserve rules, or the YE09 spot price for natural gas, oil and NGLs ($5.79/MMBtu, $76.00/Bbl of oil and $42.94/Bbl of NGLs) Net impact of SEC's new reserve rules - 12.3 Bcfe negative price-related revisions

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Positioned to deliver value in 2010 2010 Capital budget 2010 Outlook March 16, 2010 | 7 2010 guidance of 8,900 MMcfe - 9,400 MMcfe (midpoint 9,150 MMcfe or 25.1 MMcfe/d) 15.7% increase in production over December 2009 average daily production of 21.7 MMcfe/d Allocating 92% to our low-risk, high-return core areas Ozona Northeast - $25.6 mm 2 rigs - 36 gross (36 net) wells Cinco Terry - $19.9 mm 2 rigs - 48 gross (24 net) wells 2010 program substantially funded with internally- generated cash flow Focus on increasing production in core operating areas in the Permian Strategic acquisitions Bolt-on and PDP-weighted Opportunistic Balance cash flow with capital spending Increase 2010 - 2011 hedge position

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Ozona Northeast Key highlights(1) Drilling inventory map(1) (1)As of December 31, 2009. Canyon Sands tight gas, Strawn and Ellenburger development Own substantially all working interest in all depths 80% NRI Legacy asset with significant remaining development potential 134.8 Bcfe estimated proved reserves, 100% operated Low decline rates (4%-6%) in mature wells 49,850 gross (43,553 net) acres Own or operate 140 miles of gathering lines 660 identified drilling locations Evaluating reprocessed 3-D seismic to identify Strawn and Ellenburger targets March 16, 2010 | 8

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Ozona Northeast: typical Canyon well IRR Analysis (520 MMcfe EUR) Key observations Statistical, predictable results 520 - 480 MMcfe average gross EUR 396 - 366 MMcfe average net EUR (80% NRI) Premium price realization driven by high gas heat content 1,250 Btu per Mcfe Make-whole contract (wellhead) Contract expires 1Q 2011 Expected D&C costs $670k per well (8/8th) Expected breakeven at $3.50 NYMEX Decline curve Price (NYMEX), IRR & Payout Based on 520 MMcfe average gross EUR Oil $70/Bbl, NGLs $32.50/Bbl March 16, 2010 | 9

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Cinco Terry Key highlights(1) Drilling inventory map(1) (1)As of December 31, 2009. Canyon Sands tight gas development +-52% WI & 39% NRI Ellenburger development 68.7 Bcfe estimated proved reserves 50,281 gross (23,818 net) acres 558 identified drilling locations 3-D seismic shoot complete Multiple horizon potential March 16, 2010 | 10

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Cinco Terry: 3-well cross section 3-Well cross section map March 16, 2010 | 11 University 42-13 5 University 42-29 1 Baker B 201

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Cinco Terry: 3-well cross section Baker B 201 TD : 8,620' ELEV KB : 2,637' University 45-29 1 TD : 8,100' ELEV KB : 2,617' University 42-13 5 TD : 8,100' ELEV KB : 2,630' 12,469' 11,538' 6 16 CALI 0 200 GR 0.2 2,000 LLS 0.2 2,000 LLD 0.2 2,000 MSFL 0.3 -0.1 DPHI 0.3 -0.1 NPHI 0.2 2000 RT20 0.2 2000 RT30 0.2 2,000 RT60 0.2 2,000 RT90 0.3 DPHI 0.3 APF Ozone Top 7,700' 7,800' 7,900' 8,000' A' 6 16 CALI 0 200 GR 0.2 2,000 LLS 0.2 2,000 LLD 0.2 2,000 MSFL 0.3 -0.1 DPHI 0.3 -0.1 NPHI 6 16 CALI 0 200 GR -0.1 -0.1 7,700' 7,800' 7,900' 8,000' 7,700' 7,800' 7,900' 8,000' Sand Shale Gas-Filled Porosity Gas-Filled Porosity ~ 112' Gas-Filled Porosity ~ 120' Gas-Filled Porosity ~ 50' March 16, 2010 | 12

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Cinco Terry: typical Canyon well IRR Analysis (547 MMcfe EUR) Key observations Decline curve Price (NYMEX), IRR & Payout Statistical results +-52% WI & 39% NRI 547 MMcfe average gross EUR 258 MMcfe average net EUR Premium price realization driven by high gas heat content 1,220 Btu per Mcfe 93% POP contract Expected D&C Costs $810k per well (8/8th) Expected breakeven at $3.00 NYMEX Based on 547 MMcfe average gross EUR Oil $70/Bbl, NGLs $32.50/Bbl March 16, 2010 | 13

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Cinco Terry: typical Canyon/Ellenburger well Key observations Decline curve Statistical results +-52% WI & 39% NRI 653 MMcfe average gross EUR 311 MMcfe average net EUR Premium price realization driven by high gas heat content 1,220 Btu per Mcfe 93% POP contract Expected D&C costs $860k per well (8/8th) Expected breakeven less than $3.00 NYMEX IRR Analysis (653 MMcfe EUR) Price (NYMEX), IRR & Payout Based on 653 MMcfe average gross EUR Oil $70/Bbl, NGLs $32.50/Bbl March 16, 2010 | 14

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Cinco Terry: Ellenburger upside Key observations Decline curve Statistical results +-52% WI & 39% NRI 1,315 MMcfe average gross EUR 670 MMcfe average net EUR Premium price realization driven by high gas heat content 1,220 Btu per Mcfe 93% POP contract Expected D&C costs $670k per well (8/8th) IRR Analysis (1,315 MMcfe EUR) Price (NYMEX), IRR & Payout Based on 1,315 MMcfe average gross EUR Oil $70/Bbl, NGLs $32.50/Bbl March 16, 2010 | 15

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Cinco Terry 3-D seismic area March 16, 2010 | 16 3-D seismic data covers >135,000 acres in the Permian Basin

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North Bald Prairie Key highlights(1) Drilling inventory map(1) (1)As of December 31, 2009. Cotton Valley Lime, Bossier Shale and Cotton Valley Sands development 50% WI & +-40% NRI 15.5 Bcfe estimated proved reserves 8,006 gross (4,711 net) acres Approximately 2,461 net acres have been re- leased at substantially 100% WI 93 identified drilling locations Rodessa and Pettit behind pipe potential March 16, 2010 | 17

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North Bald Prairie: typical Cotton Valley well IRR Analysis (1,300 MMcfe EUR) Key observations Decline curve Price (NYMEX), IRR & Payout Statistical results 50% WI & +-40% NRI 1,300 - 1,000 MMcfe average gross EUR 507 - 400 MMcfe average net EUR Price realization 1,050 Btu per Mcfe Expected D&C costs $2.0 mm per well (8/8th) Based on 1,300 MMcfe average gross EUR March 16, 2010 | 18

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Exploratory plays Northern New Mexico - El Vado East Western Kentucky - Boomerang New Albany Shale 74,988 gross (44,759 net) undeveloped acres at 12/31/2009 Lease terms (1 year remaining primary + 5 year extensions remaining) provide option value on technology and gas prices Complete two, previously drilled wells in the New Albany Shale in 2010 After evaluating results from test wells, determine development program for the prospect Mancos Shale exploration 2,000 to 3,000 feet 90,357 gross (79,793 net) undeveloped acres at 12/31/2009 Proximity to several multi-million barrel fields (mostly crude oil) Additional prospectivity in Dakota, Morrison, Todilto and Entrada formations County ordinance finalized and drilling moratorium lifted 5/2009 Expect to begin drilling summer 2010, subject to County permitting process March 16, 2010 | 19

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AREX investment highlights 2010 Outlook Focus on increasing production in core operating areas in the Permian Strategic acquisitions Bolt-on and PDP-weighted Opportunistic Balance cash flow with capital spending Increase 2010 - 2011 hedge position March 16, 2010 | 20 (1)See important disclosures regarding liquidity and long-term debt-to-capital on page 24. (2)Based on March 9, 2010 closing price of $9.62 per share and December 31, 2009 balance sheet and reported proved reserve estimates. High quality, long-lived asset base to ride price cycles Low risk, repeatable, multi-year drilling inventory of over 1,300 identified locations Strong balance sheet heading into 2010(1) Liquidity of $85.4 million Long-term debt-to-capital of 12.8% 2010 guidance midpoint of 25.1 MMcfe/d is a 15.7% increase in production over December 2009 production of 21.7 MMcfe/d Technically driven management team with a proven track record of unconventional resource exploration, evaluation and development Attractive valuation versus peers: EV per 2009 proved reserve ~$1.06/Mcfe(2)

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Appendix

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Financial and operating guidance 2010 financial and operating guidance The table below sets forth the Company's current 2010 financial and operating guidance. The 2010 guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company's control, as further described on page 2 of this presentation. March 16, 2010 | 22

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Equity ownership Ownership of management & certain beneficial owners at 12/31/2009 (1)As of most recent public filings, 2.3 million shares are owned by non-affiliate holders of 5% or more of our outstanding common stock. March 16, 2010 | 23

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Liquidity and long-term debt-to-capital March 16, 2010 | 24 Improved liquidity Improved long-term debt-to-capital ratio Long-term debt-to-capital ratio is calculated as of December 31, 2009, and by dividing long-term debt (GAAP) of $32.3 million by the sum of total stockholders' equity (GAAP) and long-term debt (GAAP) of $252.8 million. We use the long-term debt-to-capital ratio as a measurement of our overall financial leverage. However, this ratio has limitations. This ratio can vary from year to year for the Company and can vary among companies based on what is or is not included in the ratio on a company's financial statements. This ratio 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. Liquidity is calculated by adding the net funds available under our revolving credit facility and cash and cash equivalents. We use liquidity as an indicator of the Company's ability to fund development and exploration activities. However, this measurement has limitations. This measurement can vary from year to year for the Company and can vary among companies based on what is or is not included in the measurement on a company's financial statements. This measurement 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

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Finding & development costs reconciliation (unaudited) We believe that providing measures of finding and development, or F&D, cost is useful to assist an evaluation of how much it costs the Company, on a per Mcfe basis, to add proved reserves. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our Annual Report on Form 10-K filed with the SEC on March 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 for the year ended December 31, 2009 to the information required by paragraphs 11 and 21 of ASC 932-235: March 16, 2010 | 25

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F&D costs reconciliation (unaudited) - cont. Drill-bit finding and development ("F&D") costs are calculated by dividing the sum of exploration costs and development costs for the year, by the total of reserve extensions and discoveries for the year. All-in F&D costs, including revisions, are calculated by dividing the sum of property acquisition costs, exploration costs and development costs for the year, by the total of reserve extensions, discoveries, purchases and all revisions for the year. All-in F&D costs, including revisions and the change in future development costs, are calculated by dividing the sum of property acquisition costs, exploration costs, development costs and the change in future development costs from the prior year, by the total of reserve extensions, discoveries, purchases and all revisions for the year. Definitions Reconciliation (1) Includes $170,000 in non-cash asset retirement obligations recorded in 2009. March 16, 2010 | 26

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Production replacement Production replaced from drilling alone is calculated by dividing extensions and discoveries of 30.4 Bcfe by production of 8.8 Bcfe. Production replaced from all sources is calculated by dividing net proved reserve additions of 16.7 Bcfe (the sum of extensions and discoveries and revisions) by production of 8.8 Bcfe. We use production replacement ratios as an indicator of the Company's potential ability to replace annual production volumes and grow our reserves. However, these production replacement ratios have limitations. These ratios can vary from year to year for the Company and among other oil and gas companies based on the extent and timing of discoveries and property acquisitions. In addition, since these ratios do not incorporate the cost or timing of future production of new reserves, they should not be used as a measure of value creation. March 16, 2010 | 27

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EBITDAX reconciliation (unaudited) $ thousands, except per-share amounts We define EBITDAX as (loss) income, plus (1) exploration expense, (2) impairment of unproved properties, (3) depletion, depreciation and amortization expense, (4) share-based compensation expense, (5) impairment of investment, (6) unrealized loss (gain) on commodity derivatives, (7) interest expense and (8) 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 (loss) 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. March 16, 2010 | 28

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Adjusted net income reconciliation (unaudited) $ thousands, except per-share amounts 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. March 16, 2010 | 29

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PV-10 reconciliation (unaudited) The present value of our proved reserves, discounted at 10% (PV-10), was estimated at $128.9 million at December 31, 2009. Under the Current Price Case, PV-10 was calculated based on the first-of-the-month, 12-month average for natural gas, oil and NGLs, or $3.87 per MMBtu, $61.04 per Bbl of oil and $27.20 per Bbl of NGLs, respectively. PV-10 based the Previous Price Case totaled $317.4 million and assumed the posted spot price as of December 31, 2009, for natural gas, oil and NGLs, or $5.79 per MMBtu, $76.00 per Bbl of oil and $42.94 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 of discounted future net cash flows as computed under GAAP. March 16, 2010 | 30

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Hedging positions at 12/31/2009 Natural gas and basis differential hedges (1)Percent of estimated production hedged for 2010 is based on the midpoint of 2010 production guidance. Hedging to secure capital 57% of total 2010 natural gas production hedged at a weighted average price of $6.18/Mcf(1)