Exhibit 99.1

Company October 1, 2009 Presentation

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 and Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission ("SEC") on March 13, 2009 and August 7, 2009, respectively. 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 has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The Company uses the terms "estimated ultimate recovery," "EUR," "probable," "possible" and "resource" reserves, reserve "potential," "upside" or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines may prohibit the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. October 1, 2009 | 2

Company overview Core areas of operations(1) (1)As of December 31, 2008, unless otherwise noted. (2)Based on September 21, 2009 closing price of $9.40 per share and 20.7 mm shares outstanding. (3)Net debt at June 30, 2009 was $44.8 mm. Exchange/Ticker Market cap $194.9 mm(2) Enterprise value $239.7 mm(3) October 1, 2009 | 3

Key investment highlights High quality, long-lived asset base Low risk, repeatable, multi-year drilling inventory of over 1,200 identified locations Financial flexibility Technically driven management team with a proven track record of unconventional resource exploration, evaluation and development Attractive valuation versus peers Peer comparison - EV/Mcfe ($/Mcfe)(1) (1) Source: Tudor, Pickering, Holt & Co. Weekly Valuation Sheet, September 22, 2009, and AREX reports. Based on September 21, 2009 closing price of $9.40 per share, June 30, 2009 balance sheet and December 31, 2008 reported reserve estimates. October 1, 2009 | 4

Production and reserve growth Historic growth is organically driven Ozona Northeast historically represented majority of production and reserves Other development plays now contributing (Cinco Terry and North Bald Prairie) Flexibility to decrease capital expenditure budget and still achieve stable production in 2009 Proved reserves growth (Bcfe) Production growth (MMcfe/d) (1)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. (2)Pro forma for the Neo Canyon acquisition. Observations October 1, 2009 | 5

2008 Reserve summary and unrisked potential Reserve overview(1) (1)Estimates of proved, probable and possible reserves at December 31, 2008 are based on an independent engineering study of our oil and gas properties prepared by DeGolyer and MacNaughton. Resource reserve estimates are based on internal Company studies. Probable, possible and resource reserves are unrisked and unbooked. Proved reserve mix Total reserves by category Category Oil/NGLs (MBbls) Gas (MMcf) Equivalent (MMcfe) October 1, 2009 | 6

Finding & development costs(1) Drill-bit finding and development cost $2.11/Mcfe All-in finding and development cost, including revisions $2.64/Mcfe All-in finding and development cost, including revisions and change in future development costs $2.88/Mcfe Peer comparison: All-in F&D cost Peer comparison: Drill-bit F&D cost (1)Source: Tudor, Pickering, Holt & Co. small-cap peer group. Data from publicly-filed company reports. F&D costs (non-GAAP) reconciliation and important disclosures provided on pages 30-31. 2008 F&D cost metrics October 1, 2009 | 7

Operating as a low-cost producer: 2Q 2009 operating expenses comparison 2Q 2009 LOE & severance tax(1) (1)Source: Tudor, Pickering, Holt & Co. small-cap peer group. Data from publicly-filed company reports. Lease operating expenses include transportation expenses. (2)LOE for the second quarter of 2009 included a $235,000 ($0.10 per Mcfe) reduction of our estimated ad valorem tax accrual. October 1, 2009 | 8

Second quarter 2009 operating and financial highlights In thousands, except per-share data Production (MMcfe) Revenues Net (loss) income (Loss) earnings per diluted share Adjusted net income(1) Adjusted earnings per diluted share EBITDAX(2) EBITDAX per diluted share Average realized price (per Mcfe) Three Months Ended June 30, 2009 Three Months Ended June 30, 2008 Percent Change 2,282 9,915 (671) (0.03) 2,180 0.10 10,210 0.49 4.35 2,036 24,144 928 0.04 7,312 0.35 19,029 0.91 11.86 12% (59)% (172)% (70)% (46)% (63)% $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ (1)Adjusted net income (a non-GAAP measure) reconciliation provided on page 28. (2)EBITDAX (a non-GAAP measure) reconciliation provided on page 29. October 1, 2009 | 9

2H 2009 Update Second Half of 2009 Plans West Texas acreage position(1) (1)As of June 30, 2009. JCT Wells as of July 1, 2008 acquisition. (2)Based on 1H 2009 actual production and midpoint of 2009 production guidance estimate. See page 33 for hedging schedule. (3)See page 33 for hedging schedule. Currently expect 2009 capital expenditures will not exceed $25 million Resumed drilling mid-September Cinco Terry Began 3-D seismic shoot Higher oil and NGLs production Uphole recompletion opportunities to the Canyon through existing wellbores Ozona Northeast Use 3-D seismic to high grade deepening projects targeting the Strawn and Ellenburger through existing wellbores 54% of remaining total 2009 production hedged at a weighted average floor price of $6.80/Mcf(2) Approximately 3.0 Bcf of total 2010 production hedged at a weighted average price of $6.13/Mcf(3) October 1, 2009 | 10

Ozona Northeast Key highlights(1) Drilling inventory map with JCT wells(1) (1)As of June 30, 2009, unless otherwise noted. JCT Wells as of July 1, 2008 acquisition. 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 144.4 Bcfe estimated proved reserves, 100% operated at 12/31/2008 Low decline rates (4%-6%) in mature wells 49,169 gross (44,492 net) acres Own or operate 140 miles of gathering lines 660 identified drilling locations at 12/31/2008 Evaluating reprocessed 3-D seismic to identify Strawn and Ellenburger targets October 1, 2009 | 11

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 2/2011 Expected D&C costs $670k per well (8/8th) Expected breakeven at $3.50 NYMEX Decline curve Price (NYMEX), IRR & Payout October 1, 2009 | 12 Based on 520 MMcfe average gross EUR Oil $70/Bbl, NGLs $32.50/Bbl

Ozona Northeast 3-D Seismic Structure Map - Top of the Strawn Formation October 1, 2009 | 13

Cinco Terry Key highlights(1) Drilling inventory map(1) (1)As of June 30, 2009, unless otherwise noted. Canyon Sands tight gas development +-52% WI & 39% NRI Ellenburger development 45.9 Bcfe estimated proved reserves at 12/31/2008 48,893 gross (22,899 net) acres 456 identified drilling locations at 12/31/2008 Increased POP contract from 90% to 93% Began 3-D seismic shoot Targeting uphole Canyon recompletion opportunities Multiple horizon potential 3,000 - 4,500 7,500 - 8,100 8,200 - 8,800 Wolfcamp/Spraberry Canyon Sands Ellenburger Depth in feet Formation October 1, 2009 | 14

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 October 1, 2009 | 15 Based on 547 MMcfe average gross EUR Oil $70/Bbl, NGLs $32.50/Bbl

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 October 1, 2009 | 16 IRR Analysis (653 MMcfe EUR) Price (NYMEX), IRR & Payout Based on 653 MMcfe average gross EUR Oil $70/Bbl, NGLs $32.50/Bbl

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) October 1, 2009 | 17 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

Cinco Terry Proposed 3-D seismic October 1, 2009 | 18

North Bald Prairie Key highlights(1) Drilling inventory map(1) (1)As of June 30, 2009, unless otherwise noted. Cotton Valley Lime, Bossier Shale, Bossier Sand, Cotton Valley Sands development 50% WI & +-40% NRI 20.8 Bcfe estimated proved reserves at 12/31/2008 9,301 gross (4,361 net) acres 89 locations identified at 12/31/2008 Rodessa and Pettit behind pipe potential October 1, 2009 | 19

North Bald Prairie: typical Bossier/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) October 1, 2009 | 20 Based on 1,300 MMcfe average gross EUR

Exploratory plays Northern New Mexico - El Vado East British Columbia Western Kentucky - Boomerang 25% non-operated WI 31,231 gross (7,395 net) acres at 6/30/2009 Primary targets are Doig shale, Montney tight gas sands and lower Montney shale New Albany Shale 74,988 gross (44,759 net) undeveloped acres at 6/30/2009 Long dated leases (2 year remaining primary + 5 year extensions remaining) provide long term option value on technology and gas prices 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 6/30/2009 Proximity to several multi-million barrel fields (mostly crude oil) Additional prospectivity in Dakota, Morrison, Todilto and Entrada formations Rio Arriba County drilling moratorium has delayed drilling County ordinance finalized and drilling moratorium lifted 5/2009 Expect to begin drilling summer 2010 October 1, 2009 | 21

2009 Outlook Financial flexibility to reduce drilling in low-price environment Long-lived reserves Strong balance sheet $100 mm borrowing base confirmed on 4/13/2009 $42.9 mm drawn at 7/31/2009 Long-term debt-to-capital ratio at 6/30/2009 was 17%(1) Use period of reduced operational activity to: Increase efficiencies Lower cost structure Use 3-D seismic and lease program to expand current development plays Evaluate additional growth opportunities in the Permian Basin, Appalachian Basin and elsewhere (1)Long-term debt-to-capital ratio (a non-GAAP measure) definition provided on page 32. October 1, 2009 | 22

Appendix

Financial and operating guidance 2009 financial and operating guidance The table below sets forth the Company's current 2009 financial and operating guidance. The 2009 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. October 1, 2009 | 24

Equity ownership Ownership of management & certain beneficial owners at 6/30/2009 (1)As of most recent public filings, 4.2 million shares are owned by non-affiliate holders of 5% or more of our outstanding common stock. October 1, 2009 | 25

Financial and operating data (unaudited) (1)EBITDAX (a non-GAAP measure) reconciliation provided on page 29. $ thousands, except per-unit metrics October 1, 2009 | 26

Condensed balance sheet data (unaudited) $ thousands October 1, 2009 | 27

Adjusted net income reconciliation (unaudited) $ thousands, except per-share metrics This presentation contains the non-GAAP financial measures adjusted net income and adjusted earnings per diluted share, which exclude the unrealized, pre-tax gain or loss on commodity derivatives and related income taxes. The amounts included in the calculation of adjusted net income and adjusted earnings per diluted share above were computed in accordance with GAAP. We believe adjusted net income and adjusted earnings 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. October 1, 2009 | 28

EBITDAX reconciliation (unaudited) $ thousands, except per-share metrics We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized (gain) loss 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. October 1, 2009 | 29

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 and Quarterly Reports on Form 10-Q filed with the SEC on March 13, 2009, May 6, 2009 and August 7, 2009, respectively. 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, 2008 to the information required by paragraphs 11 and 21 of Statement of Financial Accounting Standard No. 69: October 1, 2009 | 30

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 $3.5 million in non-cash asset retirement obligations recorded in 2008. October 1, 2009 | 31

Long-term debt-to-capital ratio (unaudited) Long-term debt-to-capital is calculated as of June 30, 2009, and by dividing long-term debt (GAAP) of $46.2 million by the sum of total stockholders' equity (GAAP) and long-term debt (GAAP) of $271.3 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. October 1, 2009 | 32

Hedging positions as of 6/30/2009(1) 2009 Natural gas hedges (1)Subsequent to June 30, 2009, we entered into a WAHA differential fixed price swap at $0.53 per MMBtu for 300,000 MMBtu per month for 2011. (2)Percent of estimated production hedged for 2009 is based on 1H 2009 total production and the midpoint of 2009 production guidance, or 9,050 MMcfe. (3)Percent of estimated production hedged for 2010 is based on the midpoint of total 2009 production guidance, or 9,050 MMcfe. 2010 Natural gas hedges October 1, 2009 | 33