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

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



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


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


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


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


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



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


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


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


"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


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


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


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


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


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



ETC Expansion Projects

CarthageMaypearlCleburne

Station 802

Sillsbee


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.

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

Documents

gw gas mcf daily gas

ipaa annual meeting

tcf of gas

wells acquisitions

barnett shale horizontal

potential net wells

barnett shale net acreage

bcf largest shale gas