IPAA Annual MeetingOctober 24, 2006
2IPAA Annual Meeting
Fort WorthWeatherford
Cleburne
WISE DENTON
PARKER TARRANT
HOOD JOHNSON
HILL Ouachita Thrust Front
Viola Limit
DALLAS
Tier 1
SOMERVELL
Tier 2Being tested
Core~ 94% of current production
A’
B’
1646 wells841 BCF
1827 wells687 BCF
710 wells281 BCF
248 wells27 BCF
66 wells6 BCF
1 well
2 wells
1 wellBOSQUE
291 wells89 BCF
ERATH11 wells0.4 BCF
Largest ‘Shale Gas Field’ in N. America
Upside
Low Risk
Gas in Place
400’Barnett
ViolaEllenburger
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
3IPAA Annual Meeting
4IPAA Annual Meeting
2000
2001
2002
2003
2004
2005
2006
De
nto
n
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
Ho
od
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
Jo
hn
so
n0
0
0
283,941
11,641,831
62,061,801
67,524,412
0
0
0
778
31,895
170,032
318,511
GW Gas Mcf Daily Gas Mcf
2000
2001
2002
2003
2004
2005
2006
Pa
rke
r
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
Ta
rra
nt
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
Wis
e
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
5IPAA Annual Meeting
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
6IPAA Annual Meeting
Barnett ShaleHorizontal vs. Vertical Drilling
Fracture Stimulation
Viola
Ellenburger
ProductiveBarnett Shale
Ellenburger
Viola
CoreNon-CoreCoreNon-Core
ProductiveBarnett 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
7IPAA Annual Meeting
A Hometown Growth Engine for XTO
▪ Expecting more inventory
• 50-acre spacing
• 20-acre spacing
• Re-frac volumes
• Additional leasing
* $8.00/Mcf NYMEX flat price, ROI is undiscounted
Reserve life ~ 40 years70%
25%
7%
RA
TE
(%
)
TIME (YR)
Typical Production Profile
Well Class Well Cost ($MM)
Initial Rate(MMCFPD)
Reserves(BCFE)
ROR* ROI* PV-10*($MM)
1
2
1
2
2.5
2.5
1.6
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
8IPAA Annual Meeting
"Large" Independents Rule Barnett Shale
Other350,000
Devon~650,000 Mcf/d
XTO~200,000 Mcf/d
Chesapeake ~150,000 Mcf/d
EnCana~110,000 Mcf/d
EOG~140,000 Mcf/d
9IPAA Annual Meeting
Devon EnergyBarnett 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
10IPAA Annual Meeting
XTO Energy: At Home in the Barnett Shale
▪ Net acreage: 259,000 gross (~ 209,000 net)
• 50%+ in the highly prolific Core area
▪ 2nd 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 mi2 of 3-D seismic acquired
• 210 mi2 in progress
▪ Active drilling rigs:
• 16 in CORE
• 9 in Tier-1/Tier-2
▪ Acquisitions:
• Four Sevens
• Antero Resources
• Peak Energy
XTO acreage
Fort WorthWeatherford
WISE DENTON
PARKER TARRANT
HOOD JOHNSON
HILL Ouachita Thrust Front
Viola Limit
DALLAS
SOMERVELL
BOSQUE
JACK
Cleburne
11IPAA Annual Meeting
Chesapeake EnergyBarnett 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
12IPAA Annual Meeting
EOG ResourcesBarnett 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
13IPAA Annual Meeting
EnCana CorporationBarnett Shale Overview
Statistics Gross Net
Total acres (M) 243 205
Undeveloped acres (M) 206 174
Producing gas wells 501 447
38
500
1,500
Production since 2003 Proved Reserves Unbooked ResourcePotential
Resource Opportunity (Bcf)
as of 12/31/05Source: EnCana Corp
14IPAA Annual Meeting
15IPAA Annual Meeting
ETC Expansion Projects
CarthageMaypearlCleburne
Station 802
Sillsbee
16IPAA Annual Meeting
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 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 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.