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IPAA's 2008 Oil & Gas Investment Symposium New York, New York April 7, 2008 www.approachresources.com / 6500 W. Freeway, Suite 800 Fort Worth, Texas 76116 | 817.989.9000

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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 Annual Report on Form 10-K and filed with the Securities and Exchange Commission (SEC) on March 28, 2008. 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 $338mm(1) Shares outstanding 20.6mm (1)Based on 4/2/08 closing price and 20.6mm shares outstanding.

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Management and company history Approach management/technical team has an average of 28 years of industry experience Track record of creating value for investors 1988: American Cometra (shallow & deep tight gas sands) Ross Craft joined American Cometra in 1988 American Cometra sold assets in two separate transactions in 1995 and 1997 to Range and Pioneer, respectively 1998: Athanor Resources (tight gas - U.S. & Tunisia) Funded by Yorktown Partners Sold U.S. assets in 2002 to Nuevo Energy 2002: Approach Resources founded Funded by Yorktown Partners Drilled first well in Ozona Northeast in 2004

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Areas of operation Portfolio Highlights(1) British Columbia Western Kentucky Northern New Mexico East Texas Cinco Terry Ozona Northeast Triassic Shale and Tight Gas Sands 32,700 gross (7,400 net) acres 180.4 Bcfe of proved reserves 43% proved developed, 89% natural gas 21.9 MMcfe/d average daily production for March 2008 22.5 MMcfe/d production at 3/31/2008 21 -year reserve life index 273,800 gross (191,200 net) acres 859 identified drilling locations 293 producing wells New Albany Shale Thermogenic gas 74,000 gross (44,400 net) acres Mancos Shale 90,300 gross (81,000 net) acres Cotton Valley Sands, Bossier, Cotton Valley Lime 21.4 Bcfe of proved reserves 10,300 gross (4,900 net) acres 61 identified locations - Wolfcamp, Canyon Sands, Ellenburger 18.3 Bcfe of proved reserves 21,900 gross (9,500 net) acres 119 identified locations Canyon Sands 140.7 Bcfe of proved reserves 44,600 gross (44,000 net) acres 679 identified locations (1)As of December 31, 2007 unless otherwise noted.

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Key investment highlights Identified development drilling locations Total: 859 locations Cinco Terry 119 East Texas 61 Ozona Northeast 679 Western Kentucky 27% Cinco Terry 4% East Texas 3% British Columbia 5% Ozona Northeast 11% Northern New Mexico 50% Net undeveloped acreage Total: 162,250 net acres Development inventory 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 Emerging plays British Columbia Montney tight gas / Doig shale Southwest Kentucky New Albany Shale, thermogenic gas Northern New Mexico Mancos Shale (oil) Areas

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Stock performance(1) Small cap peer group (<$2B) % return since YE07 AREX: 28.8% since YE07 return Small cap peer group median: 18.1% since YE07 return (1)Source: JPMorgan Oil & Gas Exploration and Production Weekly E&P Comp Table, 3/27/2008. -50% -40% -30% -20% -10% 0% 10% 20% 30% 40% 50% AREX BEXP CRZO CXO DPTR EPEX EAC END XCO GSX GDP ME MMR PVA PQ SGY SFY VQ WLL

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Value proposition(1) Small cap peer group (<$2B) EV/Mcfe ($) AREX: $1.97 EV/Mcfe proved reserves Small cap peer group median: $3.30 EV/Mcfe proved reserves (1)Source: JPMorgan Oil & Gas Exploration and Production Weekly E&P Comp Table, 3/27/2008. $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 AREX BEXP CRZO CXO DPTR EPEX EAC END XCO GSX GDP ME MMR PVA PQ SGY SFY VQ WLL

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Production and reserve growth Production growth (MMcfe/d) Proved reserves growth (Bcfe) (1) (3) (1)Pro 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. (2)Based on mid-point of production guidance of 8,120 MMcfe - 8,450 MMcfe released December 12, 2007. (3)Pro forma for the acquisition of the Neo Canyon interest, as if the acquisition occurred on January 1, 2006. (2) Historic growth is organically driven Ozona Northeast historically represented majority of production and reserves Currently three rigs running Redeploying capital to development drilling outside Ozona Northeast Observations 60 109 149 180 2004 2005 PF 2006 2007 4 14 18 19 23 2004 2005 2006 PF 2007 2008 (Projected)

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12/31/2007 Reserve summary and unrisked potential Reserve overview(1) Total reserves by category Reserve mix Oil 11% Gas 89% PUD 27% PD 20% Resource 18% Possible 11% Probable 23% Unbooked reserve potential: 205.5 Bcfe (1)Estimates of proved, probable and possible reserves and PV-10 through 2P reserves are based on independent engineering study of Approach's oil and gas properties prepared by DeGolyer and MacNaughton. Resource reserve estimates and PV-10 for 3P and resource reserves are based on internal company studies. Probable, possible and resource estimates are unbooked. (2)PV-10 reconciliation provided on page 29. Oil/ NGL s Gas Equivalent PV - 10 (2) CAPEX Category (M B bls) (Bcf) (Bcfe) ($MM) ($MM) Proved reserves Developed producing 937 67. 3 72.9 $ 201.7 Developed non - producing 331 3.0 5.0 11.2 $ 2.0 Undeveloped 1, 940 90. 9 102.5 13 2. 8 189.7 Total proved reserves 3,208 161. 2 180.4 $ 345.7 $ 191.7 Probable reserves 2,347 76.0 90.1 186.1 Possible reserves 904 3 8.9 44.4 102.0 Resource 704 66.8 71.0 155.0 Total 7,163 34 2.9 385.9 $ 634 ..8

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2008 Capital budget Key projects and objectives for 2008 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 Southwest Kentucky Total: $64.3mm Northern New Mexico 6% G&G, other 1% Southwest Kentucky 4% Cinco Terry 16% East Texas 22% British Columbia 5% Ozona Northeast 46%

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Ozona Northeast field Canyon Sands tight gas development Legacy asset with significant remaining development potential 140.7 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 679 identified drilling locations Drilling inventory map(1) Key highlights 2008 plans Keep 1 or 2 rigs operating full time Sustain or slightly grow production Redeploy cash flows to other areas Reprocess 3-D seismic Option to accelerate drilling in high natural gas price environment 2008 capital budget - $29.5mm (1)As of December 31, 2007 reserve report.

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Ozona Northeast typical Canyon well Statistical, predictable results 513 - 482 MMcfe average gross EUR 391 - 367 MMcfe average net EUR (80% NRI) Premium price realization driven by high gas heat content 1,260 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 - based on 482 MMcfe 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) Drill & Complete ($1,000) ($500) $0 $500 $1,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Yrs. 0% 10% 20% 30% 40% 50% 60% $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 $10.00

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Cinco Terry project Canyon Sands tight gas development Ellenburger development 18.3 Bcfe estimated proved reserves 21,900 gross (9,500 net) acres (8,500 net undeveloped) 119 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 map(1) Key highlights 2008 plans 1 rig operating full-time Drill horizontal well test into Wolfcamp Recently acquired 1,615 gross (808 net) acres 2008 capital budget - $10.9mm Drill 24 Canyon/Ellenburger/Wolfcamp wells Multiple horizon potential Depth in feet 3,000 - 4,500 7,500 - 8,100 8,200 - 8,800 Wolfcamp/Sprayberry Canyon Sands Ellenburger (1)As of December 31, 2007 reserve report.

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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 estimated 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) Drill & Complete ($1,000) $0 $1,000 $2,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Yrs. 0% 10% 20% 30% 40% 50% 60% 70% $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 $10.00

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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) Drill & Complete ($1,000) $0 $1,000 $2,000 $3,000 $4,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Yrs. 0% 50% 100% 150% 200% 250% 300% $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 $10.00

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North Bald Prairie prospect - East Texas Cotton Valley Lime, Bossier, Cotton Valley Sands development 21.4 Bcfe estimated proved reserves 10,300 gross (4,900 net) acres (50% WI & +-40% NRI) 61 locations identified Average EURs of 1.5 Bcfe (gross) Expected D&C cost per well $1.9mm (gross) Average initial producing rates of 1.6 MMcf/d Estimated average IRRs 40% Rodessa and Pettit upside D&C'd 5 producing wells since August 2007 Currently identifying next 5 locations Acreage map(1) Key highlights 2008 plans 1 rig operating full time 2008 capital budget - $14.4mm Drill 12 CVL/Bossier/CVS wells (1)As of December 31, 2007 reserve report.

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North Bald Prairie typical CVL, Bossier, CVS well Statistical, predictable results 50% WI & 40% NRI 1,504 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 producing rate of first five wells - 1.6 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 IP 723 Mcf/d TXU B-1 IP 2,271 Mcf/d Key observations Rate of return Cumulative well cash flow profile at $7.50 Henry Hub Henry Hub NYMEX ($/Mmbtu) IRR ($'000s) Drill & Complete ($2,000) ($1,000) $0 $1,000 $2,000 $3,000 $4,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Yrs. 0% 20% 40% 60% 80% 100% 120% 140% $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 $10.00

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Asset highlights and 2008 plans 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 and completed March 2008 (cleaning up post-stimulation) Drilled and completed 1st horizontal Montney test well (cleaning up post- stimulation) Participate in 4 total new wells in 2008 2008 capital budget - $3.2mm British Columbia

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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 2008 plans Plan to spud the first of 8 test wells in late 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 - Southwest 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 2008 plans Complete 2 vertical test wells in 2008 Drill up to 3 horizontal New Albany wells in 2008 Spud 1st horizontal well in the second-half of 2008 (3,500 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 As of 3/31/2008, we have approximately $7.3 MM outstanding under our credit facility Prudent use of leverage going forward Maintain ongoing financial flexibility to pursue acquisitions or accelerate development $75 MM to $100 MM borrowing base Operate our properties as a low cost producer 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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Financial and operating guidance 2008 financial and operating guidance The 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. Actual Projected 2007 2008 Production : Natural gas (MMcf) ................................. ............... 4,801 7,400 - 7,700 Oil (Mbbl) ................................. .......................... 84 120 - 125 Total (MMcfe) ................................. .................. 5,305 8,120 - 8,450 Operating costs and expenses: Lease operating expense (per Mcfe) .......................... $ 0.72 $ 0.65 - 0.70 Severance and production taxes (percent of oil and gas sales) ................................. ............................ 4 % 5% Exploration (per Mcfe) ................................. .......... $ 0.17 $ 0.28 - 0.29 General and administrative (per Mcfe) ....................... $ 2.39 $ 0.75 - 0.78 Depletion, depreciation and amortization (per Mcfe) ................................. ...................... $ 2.47 $ 2.00 - 2.50

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Projected 2008 operating expenses comparison(1) Small cap peer group (<$2B) LOE & severance tax ($/Mcfe) AREX: $1.09 LOE & severance tax ($/Mcfe) Small cap peer group median: $1.87 LOE & severance tax ($/Mcfe) (1)Source: JPMorgan Oil & Gas Exploration and Production Weekly E&P Comp Table, 3/27/2008. $0.00 $1.00 $2.00 $3.00 $4.00 AREX BEXP CRZO CXO DPTR EPEX EAC END XCO GSX GDP ME MMR PVA PQ SGY SFY VQ WLL

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Appendix A

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Condensed balance sheet $ thousands Year ended Year ended December 31, December 31, 2007 2006 Cash and cash equivalents ................................. ............. $ 4,785 $ 4,911 Other current asset s ................................. .................... 12,362 13, 200 Property and equipment, net, successful efforts method ................................. ................................. .... 230,478 132,112 Other assets ................................. .............................. 1,101 86 Total assets ................................. ........................... $ 248,726 $ 150,309 Current liabilities ................................. ........................ $ 22,017 $ 15,421 Long - term debt ................................. .......................... - 47,619 Other long - term liabilities ................................. ............. 26,890 17,697 Convertible debt ................................. ......................... - - Stockholders' equity ................................. .................... 199,819 69,572 Total liabilities and stockholders' equity ........................ $ 248,726 $ 150,309

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Financial and operating data $ thousands, except per unit metrics (1)Gives effect to our acquisition of the Neo Canyon interest, as if the acquisition had occurred on January 1, 2006. (2)EBITDAX reconciliation provided on page 28. Pro forma Pro forma Year ended Year ended Year ended Year ended December 31, December 31, December 31, December 31, 2007 2006 2007(1) 2006(1) Revenues (in thousands): Gas ................................. .................... $ 33,497 $ 41,851 $ 45,330 $ 59,417 Oil ................................. ..................... 5,617 4,821 6,955 6,813 Total oil and gas sales .......................... 39,114 46,672 52,285 66,230 Realized gain on commodity derivatives ................................. ........ 4,732 6,222 4,732 6,222 Total oil and gas sales including derivative impact ........................... $ 43,846 $ 52,894 $ 57,017 $ 72,452 Production : Gas (MMcf) ................................. .......... 4,801 6,282 6,467 8,927 Oil (MBbl) ................................. ........... 84 77 105 109 Total (MMcfe) ................................. ... 5,305 6,744 7,095 9,580 Average prices: Gas, per Mcf ................................. ....... $ 6.98 $ 6.66 $ 7.01 $ 6.66 Oil, per Bbl ................................. ......... 66.87 62.65 66.52 62.65 Total, per Mcfe ................................. .. 7.37 6.92 7.37 6.91 Realized gain on commodity derivatives, per Mcfe ........................... 0.89 0.92 0.67 0.65 Total per Mcfe including derivative impact ................................. ....... 8.26 7.84 8.04 7.56 Costs and expenses ( per Mcfe ): Lease operating expenses ........................ $ 0.72 $ 0.58 $ 0.72 $ 0.57 Severance and production taxes ................. $ 0.31 $ 0.26 $ 0.31 $ 0.26 Depletion, depreciation and amortization ................................. ..... $ 2.47 $ 2.16 $ 2.41 $ 2.19 Exploration and impairment ...................... $ 0.22 $ 0.32 $ 0.16 $ 0.23 General and administrative ...................... $ 2.39 $ 0.36 $ 1.84 $ 0.29 EBITDAX (2) ................................. ............ $ 30,351 $ 44,887 $ 41,270 $ 61,846

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EBITDAX(1) reconciliation (unaudited) $ thousands (1)EBITDAX 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. (2)Gives effect to our acquisition of the Neo Canyon interest, as if the acquisition had occurred on January 1, 2006. Pro forma(2) Pro forma(2) Year ended Year ended Year ended Year ended December 31, December 31, December 31, December 31, 2007 2006 2007 2006 Net income ................................. ...... $ 2,709 $ 21,202 $ 7,224 $ 27,864 Exploration and abandonments .............. 1,150 2,198 1,150 2,198 Depletion, depreciation and amortization ................................. 13,098 14,551 17,107 20,934 Stock based compensation expense ................................. ....... 4,646 34 4,646 34 Change in fair value of commodity derivatives ................................. .... 3,637 (8,668) 3,637 (8,668) Interest expense ............................... 5,219 3,814 5,219 3,814 Income taxes ................................. .... (108) 11,756 2,287 15,670 EBITDAX ................................. ......... $ 30,351 $ 44,887 $ 41,270 $ 61,846

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PV-10 reconciliation (unaudited) $ thousands As of December 31, 2007 (in thousands) PV-10 ................................. ................................. .......... $ 345,656 Less income taxes Undiscounted income taxes ................................. ............. 285,384 10% discount factor ................................. ....................... (155,688) Future discounted income taxes ................................. ..... 129,696 Standardized measure of discounted future net cash flows ........... $ 215,960

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Change in equity ownership (% of shares outstanding) Equity ownership Pre-offering Post-offering Shares (mm) % Shares (mm) % Secondary market issuers: Neo Canyon Exploration, L.P. 4.2 26.4% - - Management and affiliates: Yorktown Energy Partners 9. 4 58.7 % 9. 4 45.6 % Lubar Equity Fund, LLC 0.9 5.7 % 0.9 4.5 % Other officers, directors and employees 1.2 7.5% 1.2 5.8% Subtotal 11.5 71.9% 11.5 55.9% All other stockholders 0.3 1.7% 0.3 1.3% Public stockholders - - 8.8 42.8% Total 16.0 100.0% 20.6 100.0%

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Current natural gas hedges Hedging positions Volume (MMBtu) $/MMBtu Period Monthly Total Floor Ceiling Fixed NYMEX - Henry Hub Costless collars 2008 ................................. ............... 186,000 2,230,000 $ 7.50 $ 11.45 Costless collars (3rd quarter 2008) ............................... 100,000 300,000 $ 7.00 $ 9.10 Costless collars (2nd - 4th quarter 2008) .......................... 200,000 1,800,000 $ 9.00 $ 12.20 Costless collars 2009 ................................. ............... 180,000 2,160,000 $ 7.50 $ 10.50 Costless collars 200 9 ................................ 130,000 1,560,000 $ 8.50 $ 11.70 Fixed price swaps 2 nd quarter 2008 ................................. ............ 100,000 300,000 $ 8.10 4 th quarter 2008 ................................. ............. 100,000 300,000 $ 8.63 WAHA differential Fixed price swaps 2008 ................................. ............ 186,000 2,230 ,000 (0.69) Fixed price swaps 2008 (2 nd - 4 th quarter) ....................... 100,000 900,000 (0.67) Fixed price swaps 2009 ................................. ............ 200,000 2,400,000 (0.61)