San Juan, Raton & Uinta Basins

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2 San Juan, Raton & Uinta Basins 2007 Development Uinta San Juan Piceance Raton OPERATED SJB PRODUCTION MMCFPD (gross) Dominion Acquisition 171 wells completed Tight gas development 80-acre Mesaverde, Datoka 160-acre Paradox CBM Development 80/160-acre Fruitland Coal - SJB 80-acre Vermejo/Raton Coal - Raton 80/160-acre Ferron Coal - Uinta Expanded compression and gathering infrastructure Raton, Piceance, Uinta Acquisitions in the Uinta Basin Natural Buttes Drunkards Wash SJB 200 Operator '92 '94 '96 '98 '00 '02 '04 '06 '08 1

3 San Juan Basin Tight Gas Development Ute Dome Field Paradox Development 160-acre spacing 2 4 BCF/well locations ~70 BCF net potential Durango Dakota Chacra/Gallup Mesaverde 80-acre new well Colorado New Mexico Chacra/Lewis Mesaverde Farmington Ice Canyon Area New Acquisition Gallup Dakota Burro Canyon Morrison XTO acreage Paradox 8, wells planned for 2008 SJB Development Region Multi-zone 80-acre spacing BCF/well locations ~250 BCF net potential 2

4 SJB Typical Well Economics Depth Cost Rate (Peak) Gross Reserves Net Reserves (NRI 83%) Development Cost ROR ROI PV 10% PARADOX Single Zone 9,000 2,300 1, :1 5,195 DAKOTA & MESAVERDE Single Multi-pay Zone Zone 7, : , :1 2,715 FT M$ MCFPD BCF BCF $/MCFE % M$ WI range: % Economics based on NYMEX gas price of $8.00 per Mcf 3

5 Fruitland Coal Activity 20 wells planned for 2008 Successful horizontal tests expand development possibilities in the extension coal bed region 150 drill locations ~100 BCFE net potential Trend Extension Farmington Durango 80-acre drilling area 160-acre drilling area Colorado New Mexico 120 FRUITLAND COAL MMCFPD (gross) Horizontal Pilot Area XTO acreage Operator 20 0 '92 '94 '96 '98 '00 '02 '04 '06 '08 rate Typical Production Profile Build 1 year Flat 2 years 400 MCFPD 10% time 4

6 Raton Basin Development Current rate 73 MMCFPD Gathering and compression upgrades increase production capacity Expanding productive limits Western acreage Northern acreage New Elk 2008 Drilling Areas Golden Eagle RATON PRODUCTION MMCFPD (gross) Operator Facility Expansion Target 95+ MMCFPD 0 '96 '98 '00 '02 '04 '06 '08 Apache Canyon XTO leasehold 54,317 (net) acres Hill Ranch wells planned for drill locations ~ 250 BCFE net potential 5

7 Uinta Basin CBM Expanding XTO s footprint in the Ferron Coal Play through leasing and acquisitions Peak Field Rate: 40 MMcf/d 230 BCFE, 1.7 BCF/well Peak Field Rate: 240 MMcf/d 1.3 TCFE, 2.3 BCF/well Helper Buzzard Bench Field (100% WI) Operational improvements Increase takeaway capacity from 20 to 65 MMCFPD Expanding treating facilities to handle volume build 60,000 net acres, mostly undeveloped Developing on 160-acre spacing and testing on 80-acre spacing BUZZARD BENCH MMCFPD (gross) Operator Compression Facility Expansion Target 65+ MMCFPD Sanpete Co. Sevier Co. Wasatch Plateau Emery Co. Buzzard Bench San Rafael Swell Drunkards Wash Drunkards Wash Extension Ferron Sandstone outcrop Dominion Acquisition XTO: 31% WI owner XTO leasehold 10 0 '96 '98 '00 '02 '04 '06 '08 20 wells planned in Buzzard Bench for drill locations ~ 250 BCFE net potential 6

8 CBM Fields Typical Well Economics SJB Fruitland Coal Raton/ Vermejo Uinta Ferron Coal Depth Cost Rate Gross Reserves Net Reserves Development Cost ROR ROI PV 10% WI 2, :1 2, , :1 2, ,000 1, :1 2, FT M$ MCFPD BCF BCF $/MCFE % M$ % WI range: % Economics based on NYMEX gas price of $8.00 per Mcf 7

9 Uinta Basin Producing Fields Overview Monument Buttes Green River Natural Buttes Wasatch/Mesaverde Questar Gasco Deep Zone Tests Blackhawk, Mancos & Dakota West Tavaputs XTO Operated Acreage Detailed Map XTO Leasehold XTO Leasehold: ~100,000 acres (net) 8

10 Natural Buttes Field XTO is upgrading infrastructure Pipeline and compression facilities Extending producing trends Others testing deep zone potential Mancos/Blackhawk/Dakota Development plans: XTO - 20/40-acre drilling Others - testing 10-acre pilots Current 20-acre development Kings Canyon XTO Operated Leasehold Deep test 40-acre development 4,000 5,000 Green River Kings Canyon ext. Little Canyon Wasatch Trend Extensions 6,500 7,000 Mesaverde 9,000 10,000 10,000 11,000 Castlegate XTO leasehold 11,000 12,000 Blackhawk 15,000 16,000 Mancos Dakota wells planned for ,000 1,200 drill locations TCFE net potential 9

11 Natural Buttes Typical Well Economics Depth Cost Rate Gross Reserves Net Reserves (NRI - 84%) Development Cost ROR ROI PV 10% Wasatch/Mesaverde 8,000 1,400 1,000 1,450 1, :1 2,025 FT M$ MCFPD MMCFE MMCFE $/MCFE % M$ WI range: % Economics based on NYMEX gas price of $8.00 per MCF 10

12 Piceance Basin - Tight Gas XOM and XTO Location Map XTO leasehold XTO Wells 2007 Activities Farm-out earned from XOM Piceance Creek Advantage 2x pressure 3-4x pay of Southern Piceance Confirmed extensive hydrocarbon column Production tests limited Treating/pipeline infrastructure due mid-year 2008 Established 10 pads for drilling Designed for wells per pad Grand Valley Parachute Rulison Southern Piceance Reserve range: BCFE/well Production range: MMCFPD/well Mamm Creek 11

13 Piceance Basin: Well Analysis Net pay range Actual: 850-1,000 1S S Top Continuous Gas Reserve range: 3-6 BCF/well 490AS Efficiency will improve as pad drilling development begins Fit-for-purpose rig Optimizing casing design Improving completion techniques 400SB Williams Creek Formation Development drilling costs expected to be $8 10 million per well 290AS 2008 Activity 1 2 drilling rigs Production testing wells Continue evaluation Vsh Gas Rollins Cozette Cochran Iles Formation Net Pay 850 FT. Vsh Gas Net Pay 1,000 FT. 12

14 Arkoma Development Woodford Trend Oklahoma Fairway Trend Overthrust Trend Arkoma Basin outline Arkansas Fayetteville Shale Trend Field Pennsylvanian Pay Zones Alma SS Carpenter SS Nichols Tackett Turner Areci SS Borum Casey SS Dunn A SS Ralph Barton SS Dunn C SS Orr SS Hale SS N Planning drill wells in 2008 Focus on Overthrust drilling Shale development program kicks into gear Fairway Trend Overthrust Trend S Mis. Ord. Sil. Dev. Fayetteville SH Boone LS Chattanooga Penters Hunton Viola, Simpson Arbuckle 13

15 Arkoma Overthrust Trend Gragg, Booneville & Chismville fields Original spacing on 640-acres Successful drilling on 40-acre spacing Testing acre spacing OVERTHRUST PRODUCTION MMCFPD (gross) Impact for XTO additional well locations 12,000 acres leased along Ranger Anticline 20 0 '96 '98 '00 '02 '04 '06 '08 Booneville Field Gragg Field Chismville Field Witcherville Washburn Anticline Ranger Anticline Mansfield Field Waveland Field Producing fields XTO additional leasehold 14

16 Arkoma Typical Well Economics Depth Cost Rate Gross Reserves Net Reserves (NRI 87.5%) Development Cost ROR ROI PV 10% 4,500-7,500 1,000 1, :1 3,010 FT M$ MCFPD BCF BCF $/MCFE % M$ Average WI range: 20% - 100% Economics based on NYMEX gas price of $8.00 per MCF 15

17 Woodford/Fayetteville Shale Regional Trend Arkoma Basin Active Players: XTO, NFX, DVN, Antero, CHK 200+ MMCFPD XTO ~240,000 Net Acres Current Active Productive Woodford Play XTO ~120,000 Net Acres Fayetteville Play Active Players: XTO, SWN, CHK, HK 400 MMCFPD Second Woodford Play developing XTO ~40,000 Net Acres 167

18 Woodford Shale Play Southeastern Oklahoma Woodford Shale drill wells planned for 2008 Play producing 200 MMCFPD XTO has participated in 98 wells Pay section: feet XTO holds 120,000 net acres 5 rigs drilling 12 wells drilled in 2007 Sidmore 11-35H 4.0 MMCFPD 3.0 MMCFPD Antero IP 3.7 MMCFPD Chesapeake 1-13H IP 3.0 MMCFPD NFX 11.0 MMCFPD Black 2H MMCFPD Hall 4-29H 3.0 MMCFPD Johnston Est 7-21H 4.0 MMCFPD 2.0 TCFE net potential * Petroquest IP 2.8 MMCFPD Antero IP 5.3 MMCFPD McClung 7-15H 3.0 MMCFPD XTO leasehold XTO well 3D SEISMIC 17

19 Woodford Shale: Operational Comments XTO has advantages Well-bore utility experience from years of operations 3-D coverage across our acreage Technical expertise gained from other regions Participation in non-op wells provides R&D Not a cookie cutter development play Resembles technical complexity of Freestone Trend development Bad well does not broadly condemn acreage Faulted region Requires 3-D orientation to stay in zone when drilling Memories of early Barnett faults and karsts Drilling hot spots will develop based on success Infrastructure build-out needed for expansive development 18

20 Woodford Shale Typical Horizontal Well Economics Depth Cost Rate Gross Reserves Net Reserves (NRI 82%) Development Cost ROR ROI PV 10% 6,500-10,000 4,600 2, :1 5,180 FT M$ MCFPD BCF BCF $/MCFE % M$ Average WI range: 55% - 100% Economics based on NYMEX gas price of $8.00 per MCF 19

21 Fayetteville Shale Arkansas Arkansas Fayetteville Outcrop XTO 'FAIRWAY PROD Fayetteville Shale XTO holds 240,000 Net Acres 100,000 HBP 140,000 leasehold Fayetteville reserve range BCF/well Mississippi Embayment Entire play producing ~400 MMCFPD Must establish infrastructure for full-scale development XTO activities: Acquiring acreage and properties Participated in 104 non-op wells Drilled 15 wells in 2007 Committed to long-term growth plans in play 1.5 TCFE net potential 20

22 Fayetteville: Leasehold Position and Producing Wells Pope Van Buren Cleburne Independence XTO Neiheisel 2.2 MMCFPD Scotland XTO 2.5 MMCFPD Aspect Rothwell 4.5 MMCFPD SEECO GBP 2.5 MMCFPD SEECO Turner 1.7 MMCFPD Griffin Mountain Gravel Hill Cove Creek XTO Sidmore 11-35H 4.0 MMCFPD Field-wide well results Conway Faulkner have expanded the CORE of the development area New Quitman 3D SEISMIC 3D SEISMIC SEECO Arklan 3.8 MMCFPD Chesapeake Oldridge 3.8 MMCFPD XTO ACTIVITIES 6 wells producing 9 wells waiting on completion Horizontal laterals: 2,500 3, stage frac completions Little Creek XTO Morris Homestead 1.7 MMCFPD SEECO Featherston 5.4 MMCFPD XTO Well White XTO leasehold 21

23 Fayetteville Shale Typical Horizontal Well Economics Depth Cost Rate Gross Reserves Net Reserves (NRI 85%) Development Cost ROR ROI PV 10% 1,500 6,500 2,600 1, :1 2,615 FT M$ MCFPD BCF BCF $/MCFE % M$ Average WI range: 10% - 100% Economics based on NYMEX gas price of $8.00 per MCF 22

24 Statements concerning production growth, cash-flow margins, finding costs, future gas prices, reserve potential and debt levels are forward-looking statements. Financial results are subject to audit by independent auditors. These statements are based on assumptions concerning commodity prices, drilling results, production, administrative costs and interest costs that management believes are reasonable based on currently available information; however, management s assumptions and the Company s future performance are both subject to a wide range of business risks and uncertainties, and there is no assurance that these goals and projections can or will be met. In addition, acquisitions that meet the Company s profitability, size and geographic and other criteria may not be available on economic terms. Further information on risks and uncertainties is available in the Company s filings with the Securities and Exchange Commission, which are incorporated by this reference as though fully set forth herein. This presentation includes certain non-gaap financial measures. Reconciliation and calculation schedules for the non-gaap financial measures can be found on our website at Reserve estimates and estimates of reserve potential or upside with respect to the pending acquisition were made by our internal engineers without review by an independent petroleum engineering firm. Data used to make these estimates were furnished by the seller and may not be as complete as that which is available for our owned properties. We believe our estimates of proved reserves comply with criteria provided under rules of the Securities and Exchange Commission. The Securities and Exchange Commission has generally permitted oil and gas companies, in their filings made with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation test to be economically and legally producible under existing economic and operating conditions. We use the terms 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.