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IPAA Annual Meeting October 24, 2006. IPAA Annual Meeting 1 Fort Worth Weatherford Cleburne WISEDENTON PARKERTARRANT HOODJOHNSON HILL Ouachita Thrust.

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Presentation on theme: "IPAA Annual Meeting October 24, 2006. IPAA Annual Meeting 1 Fort Worth Weatherford Cleburne WISEDENTON PARKERTARRANT HOODJOHNSON HILL Ouachita Thrust."— Presentation transcript:

1 IPAA Annual Meeting October 24, 2006

2 IPAA Annual Meeting 1 Fort Worth Weatherford Cleburne WISEDENTON PARKERTARRANT HOODJOHNSON HILL Ouachita Thrust Front Viola Limit DALLAS Tier 1 SOMERVELL Tier 2 Being tested Core ~ 94% of current production A B 1646 wells 841 BCF 1827 wells 687 BCF 710 wells 281 BCF 248 wells 27 BCF 66 wells 6 BCF 1 well 2 wells 1 well BOSQUE 291 wells 89 BCF ERATH 11 wells 0.4 BCF Largest Shale Gas Field in N. America Upside Low Risk Gas in Place 400 Barnett Viola Ellenburger 150 A B Unconventional resource play Covers 14 counties 5,130 producing wells Producing +1.6 BCF/day (largest gas field in Texas) 1.80 TCF of gas produced to date Active drilling rigs +135 Huge upside potential - 26 TCF (USGS Estimate) Large resource – low recovery 94% of current production from Core area Take away capacity is expanding rapidly water bearing formation Frac barrier 5% increase in Recovery Rate = 1.3 TCF

3 IPAA Annual Meeting 2

4 3 2000 2001 2002 2003 2004 2005 2006 Denton 28,101,693 56,632,338 104,278,803 126,982,266 142,082,817 151,547,612 86,851,767 76,991 155,157 285,695 347,897 389,268 415,199 409,678 GW Gas Mcf Daily Gas Mcf 2000 2001 2002 2003 2004 2005 2006 Hood 0 36,014 108,485 25,466 20,666 4,586,507 6,477,878 0 99 297 70 57 12,566 30,566 GW Gas Mcf Daily Gas Mcf 2000 2001 2002 2003 2004 2005 2006 Johnson 0 283,941 11,641,831 62,061,801 67,524,412 0 778 31,895 170,032 318,511 GW Gas Mcf Daily Gas Mcf 2000 2001 2002 2003 2004 2005 2006 Parker 321,101 432,023 967,636 1,711,247 6,158,786 15,621,070 14,006,729 880 1,184 2,651 4,688 16,873 42,797 66,069 GW Gas Mcf Daily Gas Mcf 2000 2001 2002 2003 2004 2005 2006 Tarrant 502,774 3,077,217 17,467,044 39,313,322 73,203,534 117,535,196 82,103,530 1,377 8,431 47,855 107,708 200,558 322,014 387,281 GW Gas Mcf Daily Gas Mcf 2000 2001 2002 2003 2004 2005 2006 Wise 88,313,852 107,781,001 129,261,630 164,551,830 174,850,993 171,649,106 92,873,926 241,956 295,290 354,141 450,827 479,044 470,272 438,085 GW Gas Mcf Daily Gas Mcf

5 IPAA Annual Meeting 4 Barnett Shale - Why the Explosive Growth? 'Slickwater' fracturing (1997 - Mitchell Energy) Completion costs reduced by 60 - 70% Improved gas production Horizontal drilling Exposes the wellbore to more surface area Better control of frac Multiple wells from one pad Avoids culture –Parks, lakes, houses Higher gas prices Increased pipeline takeaway capacity Energy Transfer Crosstex Enterprise

6 IPAA Annual Meeting 5 Barnett Shale Horizontal vs. Vertical Drilling Fracture Stimulation Viola Ellenburger Productive Barnett Shale Ellenburger Viola CoreNon-CoreCoreNon-Core Productive Barnett Shale Core Verticals are good 1.5 - 2.5 Bcf/well Horizontals are better 2.5 - 6.0 Bcf/well Horizontals allow for less surface disturbance Non-Core Verticals are okay 500 - 750 MMcf/well Horizontals are significantly better 1.5 - 3.0 Bcf/well Horizontals reduce the risk of breaking into water Multiple stage fracturing

7 IPAA Annual Meeting 6 A Hometown Growth Engine for XTO Expecting more inventory 50-acre spacing 20-acre spacing Re-frac volumes Additional leasing * $8.00/Mcf NYMEX flat price, ROI is undiscounted Reserve life ~ 40 years 70% 25% 7% RATE (%) TIME (YR) Typical Production Profile Well ClassWell Cost ($MM) Initial Rate (MMCFPD) Reserves (BCFE) ROR*ROI*PV-10* ($MM) 12121212 2.5 1.6 4.0 2.5 1.5 1.0 4.0 – 5.0 2.5 – 3.0 2.0 1.5 100%+ 50%+ 60% 35% 7 - 9 4 - 5 5 4 7 - 9 3 - 4 2.6 1.5 Low-risk inventory of 750 to 950 new wells Barnett Shale Trend Economic Projections Core Non- Core 1 year 1.5 year

8 IPAA Annual Meeting 7 "Large" Independents Rule Barnett Shale

9 IPAA Annual Meeting 8 Devon Energy Barnett Shale Overview Net Acreage Core: 127,000 acres Non-Core: 540,000 acres Far West: 66,000 acres Total: 733,000 Net Production: ~650 MMcfe/d Producing wells: ~2,500 2005 activity: drilled 268 wells 2006 plans: drill 385 wells Acquisitions: Mitchell Energy Chief Production Source: Devon Energy

10 IPAA Annual Meeting 9 XTO Energy: At Home in the Barnett Shale Net acreage: 259,000 gross (~ 209,000 net) 50%+ in the highly prolific Core area 2 nd largest producer at 300 MMCFPD gross (200 MMCFPD net) Plan to drill 280 - 300 wells in 2007 (all horizontal) Producing wells: 160 vertical ~275 horizontal Seismic data coverage: 552 mi 2 of 3-D seismic acquired 210 mi 2 in progress Active drilling rigs: 16 in CORE 9 in Tier-1/Tier-2 Acquisitions: Four Sevens Antero Resources Peak Energy XTO acreage Fort Worth Weatherford WISEDENTON PARKERTARRANT HOODJOHNSON HILL Ouachita Thrust Front Viola Limit DALLAS SOMERVELL BOSQUE JACK Cleburne

11 IPAA Annual Meeting 10 Chesapeake Energy Barnett Shale Overview Fort Worth Barnett Shale Established a top-3 position in less than 3 years Now have ~180,000 net acres –Johnson –Tarrant –Dallas Four Sevens/Sinclair acquisition and DFW airport lease further enhance CHK's strong position ~2,400 potential net wells at 2.4 Bcfe/well on 55 acre spacing 18-rig program now increasing to 31 rigs by Q1'07 Source: Chesapeake Energy

12 IPAA Annual Meeting 11 EOG Resources Barnett Shale Overview Hold > 500,00 acres All acreage in gas window Recent 2006 production 140 MMcf/d, net 17 rigs running 13 in Johnson County 4 in Extension Counties Plan 18 rigs year end 2006 Targeted 2006 well count ~225 Source: EOG Resources

13 IPAA Annual Meeting 12 EnCana Corporation Barnett Shale Overview Statistics GrossNet Total acres (M) 243205 Undeveloped acres (M) 206174 Producing gas wells 501447 Resource Opportunity (Bcf) as of 12/31/05 Source: EnCana Corp

14 IPAA Annual Meeting 13

15 IPAA Annual Meeting 14 ETC Expansion Projects

16 IPAA Annual Meeting 15

17 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, managements assumptions and the Companys 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 Companys profitability, size and geographic and other criteria may not be available on economic terms. Further information on risks and uncertainties is available in the Companys 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 www.xtoenergy.com. 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 SECs 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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