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Exhibit 99.1

IPAA's 2008 Small Cap Oil & Gas Investment Symposium Hollywood, Florida February 14, 2008

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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 plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company's drilling program, production, hedging activities, capital expenditure levels and other guidance included in this 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. 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. These include risks and uncertainties relating to financial performance and results, prices and demand for oil and natural gas, availability of drilling and production equipment and personnel, availability of sufficient capital to execute our business plan, risks associated with drilling and operating wells, our ability to replace reserves and efficiently develop and exploit our current reserves and other important factors that could cause actual results to differ materially from those projected in the forward-looking statements. When considering our forward-looking statements, you should keep in mind the risk factors and other cautionary statements found in the Company's Prospectus dated November 7, 2007 and filed with the Securities and Exchange Commission (SEC) on November 8, 2007 pursuant to Rule 424(b). Information in this presentation, including 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 such information or 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. We use the terms "estimated ultimate recovery," "EUR," "probable," "possible" and "non-proven" reserves, reserve "potential" or "upside" or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines may prohibit us 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.

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About Approach Founded 2002 IPO November 14, 2007 Exchange/Ticker Nasdaq / AREX Market cap $300mm1 Shares outstanding 20.6mm 1Based on 2/5/08 closing price and 20.6mm shares outstanding.

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Key investment highlights High quality, long-lived asset base Low risk, repeatable, multi-year drilling inventory Sizeable acreage position in prospective unconventional resource plays Financial flexibility Technically driven management team with a proven track record of unconventional resource exploration, evaluation and development

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Company overview 170-180 Bcfe of estimated proved reserves2 45% proved developed, 90% natural gas 23 MMcfe/d average net daily production 20 year reserve life index 277,100 gross (189,400 net) total acres 789 identified drilling locations 295 producing wells Development inventory Portfolio highlights1 Ozona Northeast 644 622 Cinco Terry 126 124 East Texas 63 92 Identified developmental drilling locations Total: 789 locations Cinco Terry 109 East Texas 58 Ozona Northeast 622 East Texas Northern New Mexico Cinco Terry Areas of operation Ozona Northeast Western Kentucky New Albany Shale Cotton Valley Sands, Bossier, Cotton Valley Lime Mancos Shale Wolfcamp, Canyon Sands, Ellenburger Canyon Sands TEXAS NEW MEXICO KENTUCKY Doig Shale and Montney Tight Gas Sands BRITISH COLUMBIA Ozona Northeast 17100 Cinco Terry 6700 East Texas 4900 Northern New Mexico 81000 Western Kentucky 44400 Western Canada 7400 Western Kentucky 27% Cinco Terry 4% East Texas 3% Western Canada 5% Ozona Northeast 11% Northern New Mexico 50% Net undeveloped acreage Total: 161,500 net acres British Columbia 1As of December 31, 2007 except for average net daily production, which is as of February 5, 2007. 2All 2007 reserve information in this presentation is preliminary, based on company internal reports and subject to confirmation by the company's independent reserve engineers.

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Production and reserve growth Historic growth is organically driven Ozona Northeast historically represented majority of production and reserves Currently 3 rigs drilling Redeploying capital to development drilling outside Ozona Northeast Production growth (MMcfe/d) Proved reserves growth (Bcfe) Observations 2004 60 2005 109 PF 2006 149 2007 175 2004 4 2005 18 2006 18 PF 3Q 2007 20 2004 4 2005 14 2006 18 PF 2007 20 2008 (Projected) 23 1 3 1Pro forma for the acquisition of Neo Canyon Exploration, L.P.'s 30% working interest in Ozona Northeast, as if the acquisition occurred on January 1, 2007. 2Based on mid-point of production guidance of 8,120 MMcfe - 8,450 MMcfe released December 12, 2007. 3Pro forma for the acquisition of the Neo Canyon interest, as if the acquisition occurred on January 1, 2006. 4Mid-point of internal company estimate of 170-180 Bcfe of proved reserves at December 31, 2007. 2 4

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Ozona Northeast 29500 Cinco Terry 10900 East Texas 14400 Northern New Mexico 3600 Western Kentucky 1800 Western Canada 3200 G&G, other 900 2008 Capital budget Key projects and objectives Capital budget and key projects Redeploy free cash flow from legacy asset (Ozona Northeast) to other development areas Continue development drilling in Cinco Terry 15 wells drilled and completed through January 2008 Benefit from high crude oil prices High Btu content of gas with substantial NGL recoveries Test horizontal Wolfcamp Develop North Bald Prairie prospect in East Texas 5 wells drilled since August 2007 Develop British Columbia Montney tight gas sands and Doig shale project Test and evaluate prospectivity of Mancos and New Albany shales in New Mexico and Western Kentucky Total: $64.3mm Northern New Mexico 6% G&G, other 1% Western Kentucky 4% Cinco Terry 16% East Texas 22% Western Canada 5% Ozona Northeast 46%

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Ozona Northeast field Canyon Sands tight gas development Legacy asset with significant remaining development potential 138 -142 Bcfe estimated proved reserves, 100% operated Low decline rates (4%-6%) in mature wells 44,000 net acres (17,000 undeveloped) Own and operate 65 miles of gathering lines 622 identified drilling locations Drilling inventory map1 Key highlights Future plans Keep 1 or 2 rigs operating full time Sustain or slightly grow production Redeploy cash flows to other areas Option to accelerate drilling in high natural gas price environment 2008 capital budget - $29.5mm 1As of February 5, 2008.

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Ozona Northeast typical Canyon well Statistical, predictable results 480 MMcfe average gross EUR 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) Realize slight premium to Henry Hub NYMEX (on per Mcfe basis) Declining D&C costs $750k per well at 12/31/2007 $720k per well recent AFEs Estimated rate of return 27% at $7.50 Henry Hub $373k NPV per well at 10% discount rate Expected breakeven at $3.25 Henry Hub Key observations Rate of return Cumulative well cash flow profile at $7.50 Henry Hub, $85/Bbl Oil Henry Hub NYMEX ($/Mmbtu) IRR ($'000s) Total 4 5 6 7 8 9 10 2004A 0.035 0.0934 0.1588 0.2358 0.3248 0.4257 0.5376 Total 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 2004A -750 -250.02 -43 96.8 209.23 305.4 390 466.2 536.04 600.7 660.9 715.45 766.87 815.78 862.32 906.5 Drill & Complete

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Cinco Terry project Canyon Sands tight gas development Ellenburger development 14-17 Bcfe estimated proved reserves 21,900 gross (8,000 net) acres (7,000 net undeveloped) 109 identified Canyon drilling locations Drilled and completed 15 wells through January 2008 (6 Canyon/9 Ellenburger) EURs 514 MMcfe - 2 Bcfe (gross) D&C costs $700k to $850k Estimated IRRs ^ 50% Drilling inventory map1 Key highlights Future plans 1 rig operating full-time Drill horizontal well test into Wolfcamp Opportunity to reduce cost 2008 capital budget - $10.9mm Drill 24 Canyon/Ellenburger/Wolfcamp wells in 2008 Multiple horizon potential Depth in feet 3,000 - 4,500 7,500 - 8,100 8,200 - 8,800 Wolfcamp/Sprayberry Canyon Sands Ellenburger 1As of February 5, 2008.

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Total 4 5 6 7 8 9 10 2004A 0.364 0.4015 0.4387 0.4764 0.5147 0.55340000013148 0.5927 Total 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 2004A -850 -149.74 155.74 336.89 532.24 669 785 887 977 1058 1131 1197 1250 1314 1365 1412 Cinco Terry typical Canyon well Statistical, predictable results +-50% WI & +-39% NRI 514 MMcfe average gross EUR 208 MMcfe average net EUR 88% POP increasing to 90% after 1.4 Bcfe transported through system 1,290 Btu gas Fixed recoveries, fuel and shrink D&C costs (gross) $850k per well at 12/31/2007 Estimated rate of return - 50% $413k NPV per well at 10% discount rate Recompletion rate of return - 252% $333k recompletion (gross) $677k NPV per well at 10% discount rate Key observations Rate of return Cumulative well cash flow profile at $7.50 Henry Hub, $85/Bbl Oil, $57.75/Bbl NGL's Henry Hub NYMEX ($/Mmbtu) IRR ($'000s)

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Total 4 5 6 7 8 9 10 2004A 1.51 1.69 1.87 2.06 2.25 2.42 2.64 Total 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 2004A -750 639 1201 1610 1942 2226 2472 2696 2901 3090 3265 3427 3579 3723 3859 3987 Cinco Terry typical Ellenburger well Statistical, predictable results +-50% WI & +-39% NRI 1,470 MMcfe average gross EUR 604 MMcfe average net EUR 88% POP increasing to 90% after 1.4 Bcf transported through system 1,290 Btu gas Fixed recoveries, fuel and shrink D&C costs (gross) $750K per well at 12/31/2007 Estimated rate of return - 215% $1.4mm NPV per well at 10% discount rate Key observations Rate of return Cumulative well cash flow profile at $7.50 Henry Hub, $85/Bbl Oil, $57.75/Bbl NGL's Henry Hub NYMEX ($/Mmbtu) IRR ($'000s)

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Cinco Terry Ellenburger average daily production & initial potential rates1 803 903 902 905 221 222 141 2302 Initial potential 1664 563 762 1924 1806 1325 1815 1787 Average daily production 1328 347 126 1466 1700 1307 1349 1242 122 Days 398 Days 48 Days 56 Days 96 Days 19 Days 11 Days 20 Days Number of producing days 1Gross average daily and initial potential rates through February 7, 2008. Mcfe/d Well # Initial potential Average daily production

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North Bald Prairie prospect - East Texas Cotton Valley Lime, Bossier, Cotton Valley Sands development 18-21 Bcfe estimated proved reserves 13,600 gross (4,900 net) acres (50% WI & +-40% NRI) 58 locations identified Average EURs of 1.5 Bcfe (gross) Expected D&C cost per well $1.9mm (gross) Average initial potential rates of 1.7 MMcf/d Estimated average IRRs ^ 40% Rodessa and Pettit upside Drilled 5 wells since August 2007 (2 waiting on completion) Acreage map1 Key highlights Future plans 1 rig operating full time 2008 capital budget - $14.4mm Drill 12 CVL/Bossier/CVS wells in 2008 1As of February 5, 2008.

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Total 4 5 6 7 8 9 10 1557 0.0518 0.136 0.235 0.3536 0.4959 0.6659 0.86 1.33 0.6198 Total 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 2004A -2000 -760 -107 384 792 1127 1442 1728 1992 2236 2461 2661 2845 3016 3173 3318 North Bald Prairie typical CVL, Bossier, CVS well Statistical, predictable results 50% WI & 40% NRI 1,557 MMcfe average gross EUR 592 MMcfe average net EUR D&C costs (gross) $2mm per well at 12/31/2007 Estimated rate of return - 42% $892k NPV per well at 10% discount rate Average initial potential rate of the first three wells - 1.7 MMcf/d TXU North No. 2 (CVL, Bossier, CVS) IP 1,061 Mcf/d TXU No. 2 (Bossier, CVS) IP 665 Mcf/d TXU A-1 (CVL & Bossier) IP 3,418 Mcf/d Children's Home No.1 well Completed Bossier - preparing to frac CVS TXU B-1 Waiting on completion Key observations Rate of return Cumulative well cash flow profile at $7.50 Henry Hub Henry Hub NYMEX ($/Mmbtu) IRR ($'000s)

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British Columbia shale gas / tight gas play 25% non-operated working interest 32,700 gross (7,400 net) acres Primary targets are Montney tight gas sands and Doig shale 1st vertical Montney test well D&C'd October 2007 1.1 MMcfe/d IP Well awaiting pipeline hookup 1st vertical Doig test well drilled January 2008 (waiting on completion) Currently drilling 1st horizontal Montney test well Participate in 4 total new wells in 2008 2008 capital budget - $3.2mm Approach strategy Asset highlights Canadian unconventional resources (particularly shales) historically underexplored Oil Sands development will increase regional consumption of natural gas Recent successful shale tests have attracted significant attention from large E&P and integrated players Crown leasehold sales attracted bids of up to $4,000 per acre British Columbia project establishes an early foothold in the area for Approach

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El Vado East Exploration prospect - New Mexico Mancos Shale low cost exploration 2,000 to 3,000 feet 90,300 gross (81,000 net) undeveloped acres Proximity to several multi-million barrel fields (mostly crude oil) Additional prospectivity in Dakota, Morrison, Todilto and Entrada formations Acreage map Key highlights Future plans Plan to spud the first of 8 test wells in Q2 2008 Estimated dry hole cost of $200k per well 2008 capital budget - $3.6mm

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600 MMcfe EUR D&C - $850k ROR - 36% PV-10 - $789k 350 MMcfe EUR D&C - $850k ROR - 15% PV-10 - $147k Boomerang prospect - Western Kentucky New Albany Shale 74,000 gross (44,000 net) undeveloped acres Long dated leases (5 year prime + 5 year extension) provide long term option value on technology and gas prices Drilled 3 vertical tests in Q1 2007 Core analysis suggests between 350 and 600 MMcfe per 160 acre unit (recoverable) Acreage map Key highlights Future plans Complete 2 vertical test wells in 2008 Drill up to 3 horizontal New Albany wells in 2008 Spud 1st horizontal well March 2008 (3,600 ft. lateral) After evaluating results, determine development program for the prospect 2008 capital budget - $1.8mm Anticipated economic results based on core analysis

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Financial strategy Maintain conservative financial policy Debt-free balance sheet post-IPO Prudent use of leverage going forward Maintain ongoing financial flexibility to pursue acquisitions or accelerate development Fund development drilling budget substantially from operating cash flow Ozona Northeast funds development in other areas Employ commodity price hedging program Secure cash flow to fund development drilling program Use combination of swaps and collars Hedge basis differential

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Condensed balance sheet $ thousands

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Financial and operating data (unaudited) $ thousands, except per unit metrics 1Gives effect to our acquisition of the Neo Canyon interest, as if the acquisition had occurred on January 1, 2006. 2EBITDAX reconciliation provided on page 17.

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EBITDAX1 reconciliation (unaudited) $ thousands 1EBITDAX is presented in this presentation and reconciled to the generally accepted accounting principle ("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. We define EBITDAX as net income, plus (1) exploration and abandonments expense, (2) depletion, depreciation and amortization expense, (3) stock-based compensation expense, (4) change in fair value of commodity derivatives, (5) interest expense and (6) income taxes. EBITDAX is not a measure of net income or cash flow as determined by GAAP. 2Gives effect to our acquisition of the Neo Canyon interest, as if the acquisition had occurred on January 1, 2006.

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Financial and operating guidance 2007 and 2008 financial and operating guidance The 2007 and 2008 financial and operating guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond our control, as described on page 2 of this presentation and in our SEC filings. 1Gives effect to our acquisition of the Neo Canyon interest, as if the acquisition had occurred on January 1, 2007.

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Change in equity ownership (% of shares outstanding) Equity ownership

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Natural gas hedges (as of February 6, 2008) Hedging schedule