XTO Energy: Delivering Performance

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2 Energy: Delivering Performance Cash Flow is King - Record cash margins - - Paid down $1 Billion in debt - - ~1% free-cash yield - Managing Growth and Economic Returns - Production growth of 14% in Lower expected costs - The Best Portfolio of Producing Assets in the Company s History - Multiple high-impact basins - - Low F&D costs - - Confident visible inventory - 1

3 Performance Highlights CASH MARGIN REVENUES = 66% 23 67% 33% 24 66% 32% 2% 25 64% 3% 6% 26 67% 26% 7% 27 68% 27% 5% 9 mo 28 66% 31% 3% Cash Margin Expenses Cash Taxes Revenue ($MM): Net Income ($MM): Op. Cash Flow ($MM): Annual ROCE: $1,19 $322 $ % $1,948 $582 $1, % $3,519 $1,16 $2, % $4,576 $1,543 $3,78 2.8% $5,513 $1,719 $3, % $5,734 $1,554 $3, % Daily Production: Prod n Growth / Shr: % 1, % 1,33 2.3% 1, % * 1, % 2, % EOY Market Cap ($B): EOY Share Price: $5.3 $ % $9.2 $ % $16. $ % $17.3 $ % $24.9 $ % $26.8 Realized Prices Natural Gas: Oil: Cash Margin / Mcfe $4.7 $28.59 $2.77 $5.4 $38.38 $3.46 $7.4 $47.3 $4.69 $7.69 $6.96 $5.52 $7.5 $7.8 $5.63 $8.22 $88.55 $6.22 * Adjusted to include HGT distribution 2

4 Perspective on Free Cash Flow ~$5.7 Billion** $ Billions 5 4 ~$4.9 Billion** $6 Million Midstream Budget ~$2.5 B Cash Flow above Capital Budget $2.1 Billion Growth Budget $1.4 Billion Maintenance Budget* $45 Million Midstream Budget $2.75 Billion Development Budget * To maintain flat production and reserves ** First Call data as of 2/3/

5 s Hedging Positions Production: MCF or BBLS per day NYMEX Price per MCF or BBLS Natural Gas Mcfe Price 29* Natural Gas Jan Dec Oil Jan Dec Total NG Equivalent Jan Dec 1,745, 62,5 2,12, $ 8.79 $ $ Natural Gas Jan Dec Oil Jan Dec Total NG Equivalent Jan Dec 73, 27,5 895, $ 8.67 $ $ 1.96 * Includes early settled and reset swap agreements 4

6 29 Launching the Drill Bit Era Drill, Develop and Grow - $3.3 billion development budget % production increase - Operational Focus: Multiple Growth Basins - Freestone Trend - - Barnett - - Fayetteville - - Woodford - - Haynesville - - Bakken - - Marcellus - Legacy Cash Cows - West Texas - - San Juan/Rockies - - South Texas/Gulf Coast - 5

7 29 Development, Exploration & Operations Budget SJB, Raton, Uinta & Piceance 8% Bakken, Gulf Coast & Offshore 9% Mid Continent & Arkoma 15% Permian Region 8% Exploration 3% Eastern Region 32% Development and Exploration $2.75 Billion Midstream and Infrastructure $45 Million Barnett Shale 26% 6

8 Tight Gas Basins Williston Wind River Green River Uinta Piceance Denver Appalachian San Juan Anadarko Arkoma Permian ETX Arkla basins Tight gas regions Gulf Coast Growth positions Arkoma Basin Mid-Continent Piceance Basin San Juan Basin Uinta Basin Created Freestone Trend Production: 2 MMcf to > 7 MMcf 1 TCFE potential 7

9 Eastern Region - Freestone Trend 8 PRODUCTION GROWTH MMCFEPD (gross operated) / Rig Count 4 North 6 3 Rischer Store 4 2 Productive area 3,4 mi 2 N. Personville Reed Teague 2 Cumulative Production ~ 1 TCF '98 ' '2 '4 '6 '8 1 CVL Horizontals 2/4-acre spacing Oaks Freestone Production Growth Rig Count Farrar Bald Prairie Bear Grass Central 443, acres (363, net) NET RESERVE GROWTH (BCFE) 846 1,142 1,527 2,3 2,818 2,529 3,177 South acreage Hunt acreage 46 miles 75 miles '98 '99 ' '1 '2 '3 '4 '5 '6 '7 8

10 Fort Worth Basin Barnett Shale Growth JACK WISE DENTON 8 PRODUCTION GROWTH MMCFEPD (gross operated) / Rig Count 4 CORE 6 3 TIER 1 PARKER TARRANT DALLAS 4 2 Weatherford Fort Worth 2 Cumulative Production ~ 38 BCF 1 '1 '2 '3 '4 '5 '6 '7 '8 HOOD JOHNSON ELLIS Production Growth Rig Count Cleburne 25 NET RESERVE GROWTH (BCFE) 2,327 SOMERVELL 2 BOSQUE HILL Ouachita Thrust Front 15 1,428 TIER acreage

11 Shale Basins Bakken Shale Daily production: 14, BOE 45, net acres Reserves/well 3-6 MBOE Woodford Shale Daily production: 4 MMCFPD 16, net acres Reserves/well BCF Fayetteville Shale Daily production: 3 MMCFPD 38, net acres Reserves/well BCF Marcellus Shale Shallow production: 26 MMCFPD 28, net acres Reserves/well BCF Barnett Shale Gross Production: >7 MMCFPD 28, net acres (55% CORE) Reserves/well BCF TOTAL SHALE POTENTIAL 1.7 million acres Haynesville Shale 1, net acres Reserves/well BCF 1

12 Woodford Shale Play Southeastern Oklahoma 4-45 wells for operated rigs Woodford Shale $ million/well BCF/well 3D SEISMIC Churchill MMCFPD Pale Moon MMCFPD Entire play producing ~55 MMCFPD Black 2H MMCFPD OPERATED PRODUCTION MMCFPD (gross) Johnston Est 8-21H 5. MMCFPD McClung 8-15H 6. MMCFPD 2 1 leasehold well 12/6 6/7 12/7 6/8 12/8 11

13 Fayetteville: Leasehold Position and Producing Wells Pope Field-wide well results have expanded the CORE of the development area Van Buren Deltic 2.5 MMCFPD Cleburne Independence Thomas 2.7 MMCFPD McFalls 3. MMCFPD 3D SEISMIC Neiheisel 2.2 MMCFPD Scotland Griffin Mountain Gravel Hill Cove Creek New Quitman 3D SEISMIC Black 2. MMCFPD Little Creek 3D SEISMIC 3 Conway OPERATED PRODUCTION MCFPD (gross) Faulkner Johnson 3.5 MMCFPD Well White leasehold 2 1 1/7 4/7 7/7 1/7 1/8 4/8 7/8 1/ wells for operated rigs $ million/well BCF/well Entire play producing ~8 MMCFPD 12

14 Bakken Shale Position Geology: Primary Reservoir Objectives: Upper, Middle and Lower Bakken Shale Complex Three Forks/Sanish Bakken pay section: 5 15 Depth: 9, 11, 4 45 wells for 29 5 operated rigs Montana North Dakota Nesson Anticline DeAngelis 175 BOEPD Bakken Well Profile: Reserves: 3, 6, BOE/well Elm Coulee Field Williston Parshall/Sanish Field Drilling Costs: $4. $5.5 million/well Initial Rates: 3 6 BOE/day Bakken Highlights Leading position in basin 45, undeveloped acres (net) 3-D seismic covers majority of position Multiple target zones Bar Trend Leasehold Successful Three Forks Tests 13

15 Haynesville Shale Overview Pay Zones James Lime Rodessa Pettet 1, acres Travis Peak (Hosston) Cotton Valley Sand Bossier Haynesville Shale Cotton Valley Lime (Haynesville) Smackover (Gray) 15-3 feet horizontal wells for 29 2 operated rigs $7 9 million/well 4 8 BCF/well 14

16 Appalachia Acreage Position 28, net acres CHK COG RRC RRC Chief North Marcellus Shale 7, net acres RRC Atlas PetroEdge CHK PetroEdge Atlas Chief 1 12 horizontal wells for 29 1 operated rig $3 4 million/well 2 4 BCF/well HBP acreage position CHK South Marcellus Shale 21, net acres acreage Other operator Marcellus activity 15

17 The Dynamics of Gas Price and Drilling Cost U.S. Gas Rig Count () & Day rate ($M/day) Hedging allows to drill into lower costs Consistent development plans = increased efficiency Ride the wave" - upgrade your rig fleet 2% $18, $13, 25% $1,5 $7,5 $2 $16 $12 $8 $4 Gas Price ($/Mcf) Flat to -.16% +3.3% -3.17% -.14% -1.34% -2.37% -.94% +3.7% +7.47% Down U.S. Natural Gas Production Growth EIA Reported Dry Gas $ ' '1 '2 '3 '4 '5 '6 '7 '8 '9 '1 Gas Price U.S. Gas Rig Count Day Rate (1, HP Rigs) 16

18 Create Value and the Stock Price will Follow 9 8 Gold in the Vault 7 6 's stock price since IPO $13 to $522* 25 MCFE/share ~ E * Not adjusted for splits, as of January 3, 29 YE Reserves/share Low-Risk Upsides/share Additional Potential 17

19 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.