Investor Presentation

July 2010

Exhibit 99.1

2

PPT-161-July Investor Presentation

Company

Overview

(1)

Significant shale upside with a solid base of conventional assets

(1)

The

reserve

estimates

provided

throughout

this

document

are

pro

forma

for

the

Common

and

Appalachia

JV

transactions

and

effective

as

of

3.31.10

with

3.31.10

NYMEX

strip

pricing,

adjusted

for

differentials

and

excluding

hedge

effects,

unless

otherwise

noted

(2)

Haynesville

and

Marcellus

acreage

throughout

this

document

is

net

to

EXCO’s

interest

in

the

JVs;

assumes

BG

Group

exercises

their

option

to

purchase

50%

of

recently

acquired

acreage

•

1.2 Tcfe

of Proved Reserves

–

300 Mmcfe/d

of current net production, reserve life of 10.9

years

and 62% Proved Developed

–

260 Bcf

of shale assets

booked as proved with potential for

significant future reserve adds

•

Significant Unproved Upside

–

2.4 Tcfe

of probable and possible reserves

–

8.9 Tcfe

of contingent reserves

–

~0.7 million net acres

(2)

•

~78,500 net acres

in the Haynesville play

•

~93,000 net acres

in the Marcellus play

•

Pursuing additional acquisition and leasing opportunities

•

Successfully shifted focus from acquisitions to

developing shale acreage

–

Gross operated Haynesville production exceeds 500 Mmcf/d

3

PPT-161-July Investor Presentation

Reserve Base

Concentrated portfolio focused on shale resources

Proved Reserves = 1.2 Tcfe

3P Reserves = 3.6 Tcfe

3P+ Reserves = 12.5 Tcfe

Current Net Production = 300 Mmcfe/d

Gross acreage: ~851,000

Net acreage: ~653,000

Proved: 0.2 Tcfe

3P: 0.2 Tcfe

3P+: 5.9 Tcfe

Production: 17 Mmcfe/d

Gross acreage: ~364,000

Net acreage: ~327,000

Permian

Proved: 0.1 Tcfe

3P: 0.1 Tcfe

3P+:  0.3 Tcfe

Production:  20 Mmcfe/d

Gross acreage: ~190,000

Net acreage: ~138,000

East Texas / North Louisiana

Proved: 0.9 Tcfe

3P: 3.3 Tcfe

3P+: 6.3 Tcfe

Production:  263 Mmcfe/d

Gross acreage: ~297,000

Net acreage: ~188,000

Appalachia

4

PPT-161-July Investor Presentation

Recent Events

•

Significant

liquidity

created

through

2009

asset

sales

and

joint

venture

with

BG

Group

–

Reduced debt by $2.2 billion or 74% since YE 2008

–

Increased liquidity to approximately $1.0 billion

•

Continued success in the Haynesville

–

Completed 64 operated wells to date with average IP’s of 23 Mmcf/d

–

Closed

purchase

of

Common

Resources,

LLC

jointly

with

BG

Group

for

$442

(1)

million

($221

million

net to EXCO)

•

Adds ~27,600 net acres to the JV (13,800 net to EXCO) in the Shelby Trough in San

Augustine, Shelby and Nacogdoches Counties, TX; acquisition creates second focus area

–

Closed acquisition of approximately 20,000 net acres to the JV (10,000 net to EXCO) from

Southwestern Energy Company for $356 million ($178 million net to EXCO) in the Shelby Trough;

nearly all of the interests are incremental to the interests previously acquired in the area

•

Closed Appalachia Joint Venture with BG Group for $985 million

–

Received $835

(1)

million cash proceeds

–

Additional $150 million deep drilling carry to be satisfied in 2011 or 2012

•

EXCO is positioned for unmatched organic growth within cash flow

–

Began 2010 with 234 Mmcfe/d, Q1 2010 average of 264 Mmcfe/d

–

Expect

Q4

2010

to

average

375

–

395

Mmcfe/d

resulting

in

~60%

growth

for

2010

–

Targeting

30

–

40%

growth

for

the

next

five

years

(1)

Subject

to

normal

post

closing

purchase

price

adjustments

5

PPT-161-July Investor Presentation

Liquidity and Financial Position

(1)

Includes

$70.0

million

of

restricted

cash

at

3/31/10

(2)

Excludes

unamortized

bond

premium

of

$3.1

million

(3)

Net

of

$15.2

million

in

letters

of

credit

Common

Appalachian

Southwestern

Pro Forma

Consolidated ($ in thousands)

March 31, 2010

Acquisition

Joint Venture

HNVL Acquisition

March 31, 2010

Cash

(1)

117,792

$         

-

$                

-

$                

-

$                  

117,792

$         

Bank debt (L + 200 - 300bps)

762,543

220,800

(835,200)

177,900

326,043

Senior notes (7 1/4%)

(2)

444,720

-

-

-

444,720

Total debt

1,207,263

$      

220,800

$         

(835,200)

$        

177,900

$          

770,763

$         

Net debt

1,089,471

$      

220,800

$         

(835,200)

$        

177,900

$          

652,971

$         

Borrowing base

1,300,000

$      

-

$                

(100,000)

$        

-

$                  

1,200,000

$      

Unused borrowing base

(3)

522,257

$         

-

$                

-

$                

-

$                  

858,757

$         

Unused borrowing base plus cash

(3)

640,049

$         

-

$                

-

$                

-

$                  

976,549

$         

•

Borrowing base reduced to $1.2 billion as a result of the JV transaction

•

Liquidity of ~ $1 billion following the acquisition of Southwestern Energy’s

Haynesville/Bossier assets

6

PPT-161-July Investor Presentation

Production Profile

Achieved our 2009 strategic plan; positioned for significant growth

•

Completed significant divestment program in 2009

•

Focused portfolio on Haynesville, Bossier and Marcellus shales

•

Prepared

to

deliver

significant,

sustained

organic

production

growth

of

50

–

60%

during

2010

(1)

Pro

forma

for

Common

Acquisition,

Appalachia

JV,

and

Southwestern

Energy

HVNL

Acquisition

-

50

100

150

200

250

300

350

400

450

$-

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

Actual production

Production guidance midpoint

Outstanding net debt

7

PPT-161-July Investor Presentation

Net Asset Value Summary

Pro forma for the Common acquisition, Appalachian JV, and SWN HVNL acquisition

In millions, except per share and per unit

Low Case

High Case

E&P

Proved Reserves - 1.2 Tcfe at $2.00 & $2.50 per Mcfe

2,400

$       

3,000

$       

Unproved Reserves (Conventional) - 0.9 Tcfe at $0.20 & $0.40 per Mcfe

180

360

Unproved Reserves (Haynesville) - 3.7 Tcf at $0.30 & $0.50 per Mcf

1,110

1,850

Unproved Reserves (Bossier) - 1.1 Tcf at $0.20 and $0.40 per Mcf

230

460

Unproved Reserves (Marcellus/Huron) - 5.6 Tcf at $0.15 & $0.25 per Mcf

833

1,388

BG Group Carry as of 3/31/10

464

464

E&P Assets

5,217

$       

7,522

$       

Midstream

TGGT - 8x and 10x 2011 EBITDA

720

900

Vernon Gathering

60

60

Midstream Assets

780

$         

960

$         

Hedges

Hedge Value

150

150

Total Asset Value

6,147

$       

8,632

$       

Less:  Net Long-term Debt

653

653

Equity Value

5,494

$       

7,979

$       

Fully Diluted Shares

216

216

NAV per Share

25.43

$       

36.94

$       

8

PPT-161-July Investor Presentation

Unmatched NAV Growth

Southwestern transaction will enhance growth profile

(1)

Ranges

based

on

the

midpoint

of

2010

guidance

(2)

2014

prices

based

on

$5.00

-

$6.00

natural

gas

and

range

of

production

volumes

•

Ability

to

grow

NAV

per

share

significantly

even

in

a

low

commodity

price

environment

2010E

(1)

2014 Target

(2)

Production (Mmcfe/d)

319

900 -

1,000

Proved Reserves (Tcfe)

1.2

5.0 -

6.0

EBITDA (Millions)

$506

$1,250 -

$1,600

Cash Flow (Millions)

$458

$1,200 -

$1,550

Capital Expenditures (Millions)

$504

$1,100 -

$1,300

50% of TGGT EBITDA (Millions)

$30

$160

Net Debt (Millions)

$725

$675 -

$975

NAV per Share

$25 -

$37

$50 -

$60

9

PPT-161-July Investor Presentation

Production

and

Cash

Flow

Growth

(1)

Target cash flow neutral spending

(dollars in millions)

2010

2011

2012

2013

2014

Average Rig Counts:

Haynesville/Bossier Area

17

22

27

27

27

Marcellus Area

2

5

10

14

16

Permian Area

2

2

3

2

-

Total

21

29

40

43

43

Production (Mmcfe/d)

319

500

650

800

950

Cash Flow

458

$     

700

$     

950

$     

1,150

$  

1,200

$  

Total CAPEX

774

$     

880

$     

1,100

$  

1,150

$  

1,200

$  

Less: Carry

(270)

(250)

-

-

-

Net CAPEX

504

$     

630

$     

1,100

$  

1,150

$  

1,200

$  

•

Drilling carries fund capital spending growth during activity ramp up period

•

Cash flow grows as carries expire enabling self funding of capital spending levels

(1)

Based

on

midpoint

of

estimates

and

assumes

gas

prices

of

$5.25,

$5.50,

$5.75,

and

$6.00

and

oil

prices

of

$75.00,

$77.50,

$80.00

and

$80.00

for

2011

–

2014;

2010

prices

based

on

midpoint

of

guidance

10

PPT-161-July Investor Presentation

Quarterly 2010 Guidance

Will update for Southwestern transaction with Q2 2010 earnings call

(1)

Non-cash

interest

expense

in

Q2

includes

write-off

of

deferred

financing

costs

associated

with

amended

credit

facility

(2)

2010

estimates

based

on

natural

gas

and

oil

NYMEX

prices

of

$4.09

and

$76.88

for

Q2,

$4.50

and

$70.00

for

Q3,

and

$5.00

and

$72.50

for

Q4

(3)

Includes

$37.9

million

of

cash

proceeds

received

Q1

2010

for

early

termination

of

hedges

related

to

dispositions,

and

excludes

EXCO’s

share

of

TGGT

EBITDA

Q1 2010

(dollars in thousands, except per unit amounts)

Actual

Low

High

Low

High

Low

High

Low

High

Production:

Oil -

Mbbls

159

130

141

128

138

127

139

544

576

Gas -

Mmcf

22,837

24,884

25,727

29,595

30,914

33,736

35,507

111,051

114,984

Mmcfe

23,791

25,662

26,572

30,360

31,740

34,500

36,340

114,313

118,443

Mmcfe/d

264

282

292

330

345

375

395

313

325

Differentials to NYMEX:

Oil per Bbl

(3.47)

$       

(4.75)

$       

(4.15)

$       

(4.75)

$       

(4.15)

$       

(4.75)

$       

(4.15)

$       

(4.38)

$       

(3.96)

$       

Gas per Mcf

98.3%

97.0%

99.0%

97.0%

99.0%

96.0%

98.0%

97.0%

98.6%

Lease operating expense

18,843

$     

19,300

$     

22,300

$     

17,600

$     

20,600

$     

18,000

$    

21,000

$    

73,740

$     

82,740

$     

Non-cash stock based compensation -

LOE

350

$         

300

$         

500

$         

300

$         

500

$         

300

$         

500

$         

1,250

$       

1,850

$       

Gathering expense -

per Mcfe

0.47

$        

0.52

$        

0.55

$        

0.52

$        

0.56

$        

0.52

$        

0.57

$        

0.49

$        

0.52

$        

Production tax rate

6.0%

6.0%

7.0%

6.0%

7.0%

6.0%

7.0%

6.0%

6.8%

Other income

467

$         

250

$         

500

$         

250

$         

500

$         

250

$         

500

$         

1,220

$       

1,970

$       

Depletion rate per Mcfe

1.43

$        

1.45

$        

1.60

$        

1.45

$        

1.60

$        

1.45

$        

1.60

$        

1.45

$        

1.57

$        

Depreciation rate per Mcfe

0.20

$        

0.20

$        

0.25

$        

0.20

$        

0.25

$        

0.20

$        

0.25

$        

0.20

$        

0.24

$        

Asset retirement obligation

1,089

$       

1,100

$       

1,400

$       

1,100

$       

1,400

$       

1,100

$      

1,400

$      

4,390

$       

5,290

$       

Cash G&A

22,160

$     

20,700

$     

22,700

$     

18,600

$     

20,600

$     

19,000

$    

21,000

$    

80,460

$     

86,460

$     

Non-cash stock based compensation -

G&A

4,259

$       

3,400

$       

3,800

$       

3,700

$       

4,100

$       

6,500

$      

7,500

$      

17,860

$     

19,660

$     

Interest expense -

cash

12,742

$     

12,500

$     

14,500

$     

10,000

$     

12,000

$     

10,000

$    

12,000

$    

45,240

$     

51,240

$     

Interest expense -

non-cash

(1)

(90)

$          

4,800

$       

5,800

$       

1,000

$       

1,500

$       

1,000

$      

1,500

$      

6,710

$       

8,710

$       

Equity method income in TGGT Holdings, LLC

89

$           

5,000

$       

6,000

$       

8,000

$       

9,000

$       

12,000

$    

13,000

$    

25,090

$     

28,090

$     

Tax rate

40%

40%

40%

40%

40%

40%

40%

40%

40%

Cash tax rate

0%

0%

0%

0%

0%

0%

0%

0%

0%

CAPEX

130,491

$   

115,700

$   

135,700

$   

111,000

$   

131,000

$   

116,800

$   

136,800

$   

473,990

$   

533,990

$   

Fully diluted shares outstanding

215,666

215,000

217,000

215,500

217,500

216,000

218,000

215,500

217,000

Adjusted EBITDA at midpoint

(2,3)

148,527

EXCO's

share of TGGT EBITDA

1,094

$       

5,500

$       

7,500

$       

8,000

$       

10,000

$     

12,000

$    

14,000

$    

26,594

$     

32,594

$     

2010

$ 505,900

$ 94,600

$ 120,100

$ 142,700

Q2 2010E

Q3 2010E

Q4 2010E

11

PPT-161-July Investor Presentation

Capital Spending Summary

Focus on the shales

$ in millions

2010E

Haynesville / Bossier

278

$     

Marcellus

134

Conventional

64

Corporate

28

Total CAPEX

504

Investment in TGGT Holdings, LLC

80

Total CAPEX including TGGT

584

Less: BG Group acreage reimbursments

(130)

Total Investing Activities

454

$     

2010 Capital Spending

Marcellus

23%

Haynesville /

Bossier

47%

Conventional

11%

Corporate

5%

TGGT Holdings

14%

•

~85% of capital directed to shale activity

12

PPT-161-July Investor Presentation

Current Derivatives Position

•

Cash settlements for Q1 2010 totaled $77.0 million

–

$39.1 million was received in the normal course of business

–

An additional $37.9 million was received in connection with early termination

of certain 2010 derivatives

•

Expect to add additional hedges for 2011 and 2012

NYMEX

Contract

Contract

Contract

natural gas

price per

NYMEX oil

price per

Equivalent

price per

% Hedged

Mmcf

Mcf

Mbls

Bbl

Mmcfe

Equivalent

forecast

(1)

Q2 2010

13,803

7.16

$    

111

114.96

$     

14,471

7.72

$       

55%

Q3 2010

13,940

7.16

113

114.96

14,616

7.72

47%

Q4 2010

13,940

7.21

113

114.96

14,616

7.76

41%

2011

31,025

6.54

548

111.32

34,310

7.69

24%

2012

16,470

6.05

92

109.30

17,019

6.44

12%

2013

5,475

5.99

-

-

5,475

5.99

4%

    Total

94,653

6.70

$    

976

112.39

$     

100,508

7.41

$       

(1)

Based

on

the

midpoint

of

2010

production

guidance,

Q4

2010

midpoint

held

flat

for

2011-2013

13

PPT-161-July Investor Presentation

Haynesville Assets and Efforts

•

~78,500 net Haynesville acres with

significant held by production

position

•

Average IP rate from our operated

Haynesville horizontal wells in

DeSoto

Parish continues to be

approximately 23

Mmcf

per day

•

Currently testing various drilling and

completion methods to improve our

recoveries and reduce costs

–

Pad drilling and spacing tests;

completed 4 wells on 80-acre

spacing off of same pad in June

2010

–

Frac

sizes and cluster spacing

–

Frac

optimization through

different types and combinations

of proppant

EXCO / BG

JV Area

TX

LA

AR

Common Acquisition Area

14

PPT-161-July Investor Presentation

Shelby Area

Haynesville and Middle Bossier assets

•

Located in Shelby Trough in Shelby,

San Augustine & Nacogdoches

Counties, TX

•

Nine horizontal shale wells flowing to

sales (8 Haynesville, 1 Bossier)

•

Large acreage holdings in three areas

totaling 60,843 gross & 47,345 net

acres (JV interest)

•

Three acreage areas

–

North area

–

~11,250’

to Bossier

–

~11,500’

to Haynesville

–

Center area

–

~12,750’

to Bossier

–

~13,000’

to Haynesville

–

South area

–

~14,250’

to Bossier

–

~14,500’

to Haynesville

•

3 operated rigs currently running

•

First EXCO operated completion

flowing more than 23 Mmcf/d

Haynesville

31 Mmcf/d

IP

Haynesville

12 Mmcf/d

IP

Haynesville

3 wells > 15 Mmcf/d

IP

Bossier

12 Mmcf/d

IP

Bossier

9 Mmcf/d

IP

Bossier

20 Mmcf/d

IP

Bossier

21 Mmcf/d

IP

Prior Operator Results

Last three Haynesville wells

21.0, 18.1 and 22.1 Mmcf/d

IP’s;

First Middle Bossier well

11 Mmcf/d

IP

EXCO Lease Position

Haynesville Shale Area

Haynesville Shale Well

Bossier Shale Well

15

PPT-161-July Investor Presentation

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

EXCO

Operated

Haynesville

IP's

DeSoto

Parish,

LA

IP, Mcf/d

Haynesville IP Rate Consistency

23 Mmcf/d

average IP in DeSoto

Parish

(1)

•

Excludes

4

wells

in

DeSoto

Parish

(2

testing

restricted

choke,

and

2

outside

of

DeSoto

core)

•

Now have 64

operated Haynesville horizontal wells to sales

•

Monitor pressure drawdown on every well; currently testing restricted choke on 2 wells

•

Initiated pad drilling operations; completed first 4 pad wells in June 2010 

(1)

EXCO

IP’s

defined

as

highest

24

hour

average

flow

rate

to

sales

Average

Desoto

Parish

IP

rate

of

23 Mmcf/d

16

Haynesville Type Curve -

DeSoto

Parish, LA

Conservatively booked with significant upside based on actual decline rates

b = 1.00

EUR = 6.6 Bcfe

b = 1.25

EUR = 7.6 Bcfe

b = 1.75

EUR = 9.6 Bcfe

EXCO’s

current

proved type curve

17

PPT-161-July Investor Presentation

EXCO Gross Operated Haynesville Shale Forecast

Poised to deliver significant growth in Haynesville production

~2,000 Mmcf/d

Production (High Case)

Currently ~500 Mmcf/d

Gross

~ 939 Mmcf/d

Production

~1,600 Mmcf/d

Production

•

Have secured firm transportation to ensure takeaway; continuing to evaluate additional

takeaway opportunities as needed

Firm Transportation

~1,700 Mmcf/d

Production (Low Case)

18

PPT-161-July Investor Presentation

•

Drilling program underway

–

Plan at least 11 horizontals in 2010

–

Built-for-purpose drilling rig under long term

contract delivered February 2010

–

Contracted to add two additional rigs

•

Completed two horizontal wells

with IP’s of 2.9 and 2.2 Mmcf/d

from 8 stage fracs

–

One of these wells had 8 stages completed over

its planned 2,500’

lateral

–

The other well was drilled to a lateral length of

4,600’

but completed only over 2,500’

(casing

problem)

•

Opportunity to complete the remaining

seven stages at a later date

•

Solidify land position

–

Continue to build acreage position

–

Current net leasehold position is approximately

325,000 net acres with more than 93,000 net

acres in the over-pressured fairway

–

Focus

on adding contiguous acreage positions

which allow for multi-well pad operations

•

Identify and develop access to gas

markets

Marcellus Activity

19

PPT-161-July Investor Presentation

TGGT Midstream Operations

Additional expansion projects in Shelby Trough

•

TGGT throughput currently totals approximately 1.1

Bcf/d

•

Construction of 36 inch, 29 mile Haynesville header

system completed

•

Throughput

capacity

in

excess

of

1.5

Bcf/d

with

the

opportunity to increase throughput with compression

and system management

•

Continuing to add high pressure flow lines to gather

production

•

Will have amine and glycol facilities with capacity to

treat 1 Bcf/d

of natural gas to meet pipeline quality

requirements during 2010; now have capacity > 800

Mmcf/d

•

Interconnects to several major pipelines with access

to multiple markets

–

Regency

–

Crosstex

–

Centerpoint

–

Gulf South

–

ETC Tiger (Q1 2011)

–

Enterprise Acadian (Q3 2011)

TGGT Holly System

TGGT  East TX / North LA System

A

BG  Group

–

EXCO 

alliance

20

PPT-161-July Investor Presentation

Forward Looking Statements

This

presentation

contains

forward-looking

statements,

as

defined

in

Section

27A

of

the

Securities

Act

and

Section

21E

of

the

Securities

Exchange

Act

of

1934,

or

the

Exchange

Act.

These

forward-looking

statements relate to, among other things, the following:

•

our future financial and operating performance and results;

•

our business strategy;

•

market prices;

•

our future use of derivative financial instruments; and

•

our plans and forecasts.

We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

We use the words "may," "expect," "anticipate," "estimate," "believe," "continue," "intend," "plan," "budget" and other similar words to identify forward-looking statements. You should read statements that

contain these words carefully because they discuss future expectations, contain projections of results of operations or of our financial condition and/or state other "forward-looking" information. We do not

undertake

any

obligation

to

update

or

revise

publicly

any

forward-looking

statements,

except

as

required

by

law.

These

statements

also

involve

risks

and

uncertainties

that

could

cause

our

actual

results

or

financial condition to materially differ from our expectations in this presentation, including, but not limited to:

•

fluctuations in prices of oil and natural gas;

•

imports of foreign oil and natural gas, including liquefied natural gas;

•

future capital requirements and availability of financing;

•

continued

disruption

of

credit

and

capital

markets

and

the

ability

of

financial

institutions

to

honor

their

commitments,

such

as

the

events

which

occurred

during

the

third

quarter

of

2008

and

thereafter, for an extended period of time;

•

estimates of reserves and economic assumptions used in connection with our acquisitions;

•

geological concentration of our reserves;

•

risks associated with drilling and operating wells;

•

exploratory

risks,

including

our

Marcellus

and

Huron

shale

plays

in

Appalachia

and

our

Haynesville/Bossier

shale

play

in

East

Texas/North

Louisiana;

•

risks associated with operation of natural gas pipelines and gathering systems;

•

discovery, acquisition, development and replacement of oil and natural gas reserves;

•

cash flow and liquidity;

•

timing and amount of future production of oil and natural gas;

•

availability of drilling and production equipment;

•

marketing of oil and natural gas;

•

developments in oil-producing and natural gas-producing countries;

•

title to our properties;

•

competition;

•

litigation;

•

general economic conditions, including costs associated with drilling and operation of our properties;

•

environmental or other governmental regulations, including legislation to reduce emissions of greenhouse gases;

•

receipt

and

collectibility

of

amounts

owed

to

us

by

purchasers

of

our

production

and

counterparties

to

our

derivative

financial

instruments;

•

decisions whether or not to enter into derivative financial instruments;

•

potential acts of terrorism;

•

actions of third party co-owners of interests in properties in which we also own an interest;

•

fluctuations in interest rates; and

•

our ability to effectively integrate companies and properties that we acquire..

21

PPT-161-July Investor Presentation

Forward Looking Statements (continued)

We believe that it is important to communicate our expectations of future performance to our investors.  However, events may occur in the future that we are unable to accurately predict, or over which we have no

control.  You are cautioned not to place undue reliance on a forward-looking statement.  When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this

presentation, and the risk factors included in the Annual Reports on Form 10-K and our Quarterly Reports on Form 10-Q.

Our

revenues,

operating

results,

financial

condition

and

ability

to

borrow

funds

or

obtain

additional

capital

depend

substantially

on

prevailing

prices

for

oil

and

natural

gas,

the

availability

of

capital

from

our

revolving

credit

facilities

and

liquidity

from

capital

markets.

Declines

in

oil

or

natural

gas

prices

may

materially

adversely

affect

our

financial

condition,

liquidity,

ability

to

obtain

financing

and

operating

results.

Lower

oil

or

natural

gas

prices

also

may

reduce

the

amount

of

oil

or

natural

gas

that

we

can

produce

economically.

A

decline

in

oil

and/or

natural

gas

prices

could

have

a

material

adverse

effect

on

the

estimated

value

and

estimated

quantities

of

our

oil

and

natural

gas

reserves,

our

ability

to

fund

our

operations

and

our

financial

condition,

cash

flow,

results

of

operations

and

access

to

capital.

Historically,

oil

and

natural

gas

prices

and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

Effective January 1, 2010, the United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil

and

gas

that

are

estimated

to

be

recoverable

with

a

high

degree

of

confidence),

but

also

"probable"

reserves

(i.e.,

quantities

of

oil

and

gas

that

are

as

likely

as

not

to

be

recovered)

as

well

as

"possible"

reserves

(i.e.,

additional

quantities

of

oil

and

gas

that

might

be

recovered,

but

with

a

lower

probability

than

probable

reserves).

As

noted

above,

statements

of

reserves

are

only

estimates

and

may

not

correspond

to

the

ultimate

quantities

of

oil

and

gas

recovered.

Any

reserve

estimates

provided

in

this

presentation

that

are

not

specifically

designated

as

being

estimates

of

proved

reserves

may

include

estimated

reserves

not

necessarily

calculated

in

accordance

with,

or

contemplated

by,

the

SEC's

latest

reserve

reporting

guidelines.

Investors

are

urged

to

consider

closely

the

disclosure

in

our

Annual

Report

on

Form

10-K

for

the

fiscal

year

ended

December

31,

2009,

which

is

available

on

our

website

at

www.excoresources.com

under

the

Investor

Relations

tab

or

by

calling

us

at

214-368-2084.