Q1 ‘15 Q2 ‘15 Q3 ‘15 Q4 ‘15
Service
Agreement
Debt &
Contract
Restructuring
Operations
Operational &
Corporate
Overhead
• Entered into a services and investment agreement with a subsidiary of Bluescape to drive performance improvements
•
•
Suspended dividend to increase liquidity
• Amended credit agreement to increase financial flexibility
• Decreased capital budget by
35% from ’14 to better align with commodity prices
Reduced workforce by 15%
• Appointed C. John Wilder
Executive Chairman, leading
EXCO’s turnaround strategy
• Renegotiated transportation agreement in NLA saving ~$9 million per year
• Announced series of transactions which resulted in total debt reduction of
$413MM
• Raised $300MM 2 nd Lien from Fairfax
• Executed $400MM debt for debt exchange
• Implemented new drilling and completion designs
• Increased EUR expectations by 15% for ETX Haynesville wells
• Realigned internal resources and flattened corporate organization
• Renegotiated sales contract in South Texas improving realized oil price
• Suspended South Texas drilling due to depressed oil price
• Renegotiated over 75 contracts realizing $4.4MM of savings
• Renegotiated a natural gas sales contract in NLA improving cash flow by
$1.5MM - $2.0MM per year
• Repurchased $90MM of debt principal in the open market through Feb ‘16 realizing interest savings of $6.4MM per year
• Announced 1H ’16 drilling and completion budget of
$70MM a reduction of
$101MM, or 59%, versus ‘15 comparable period
• Reduced workforce by an additional 32%
2

Focus Area # Improvement Plan
Improve Debt Structure To
Provide Structural Liquidity
1
’15 Review
• Reduced debt principal by $304MM during ‘15
• Executed a series of debt exchange and debt repurchases that extended the runway by 33%
’16 Focus
• Re-affirm borrowing base
• Continue open market repurchases
• Evaluate M&A and alternative financing opportunities
Liability
Management
Operational
Performance
2
3
4
Restructure Gathering And
Transportation Contracts To
Provide Liquidity
Improve Drilling And
Completion Performance To
Improve Capital Returns
• Renegotiated Haynesville and Eagle
Ford transportation rates and saved over $10MM per year
Reduce G&A Load To Reduce
Fixed Cost Burden
• Reduced total headcount by 243, or
44%, since year-end ’14
• Eliminated additional benefits
• Reduce underutilized contracts with fee structures above current market rates
• Evaluate issuance of secured debt to gathering and transportation providers in exchange for cost relief
• Realize full year of cost savings from
‘15 initiatives
• Continue to reduce G&A and target an additional $8MM run rate reduction in overhead costs
• Improved well design and efficiency, renegotiated cost reduction on ~95% of cost items; achieved overall 28% reduction in D&C and improved ETX
EUR expectations by 15%
• Target additional $5MM reduction in
LOE
Capital
Deployment
5
Implement A “Liquidity
Driven” Prioritized Capital
Allocation System To Ensure
Highest And Best Use Of
Capital
• Four rig $229MM drilling and completion capital program for fullyear ’15
• Total capital expenditures of $277MM,
$23MM lower than budget
• Approved two rig drilling and completion capital program of
$70MM for 1H ’16 is a 59% reduction versus comparable ‘15 period
• Total capital budget of $103MM
3

Pre and Post Debt Restructuring
15-16; Mixed Measures
$MM Unless Otherwise Noted
Cash And Restricted Cash 1
Credit Agreement Drawn
2nd Lien Term Loans 2
’18 Senior Notes
’22 Senior Notes
Gross Debt 2
Net Debt 2
Interest Coverage Ratio Covenant
1 st Lien Leverage Ratio Covenant
Pre Res.
Sept ’15
Post Res.
Feb ’16
Delta
%
42
300
0
750
500
1,550
1,508
2.00x
NA
1.25x
2.50x
1
60 43
95 (68)
700 NA
149 (80)
183 (63)
1,127 (27)
1,067 (29)
’15 & Early ’16 Accomplishments
• Raised $300MM 2 nd Lien Term Loan new money at
2
12.5% from 3 rd largest shareholder to repay revolver
• Issued $400MM 2 nd Lien Term Loan at 12.5% in exchange for $828MM of unsecured notes, improving forward cash flow by ~$300MM and extending maturity runway by 33%
• Repurchased additional $90MM of unsecured notes in the open market
• Obtained consent from ‘18 senior notes to maintain
$1.2B secured debt capacity
• Currently have $125MM of secured liens capacity
• Amended credit agreement to remove total leverage ratio (Net Debt/EBITDA) and reduce interest coverage ratio (EBITDA/Interest) from 2.0x to 1.25x
3
’16 Focus
• Re-affirm $375MM borrowing base
• Continue opportunistic open market repurchases of debt
• Evaluate M&A transactions and alternative financings to enhance liquidity
Total Leverage Ratio 4.5x-6.0x Removed
EXCO will focus on restructuring its debt burden to extend fixed maturities, enabling a stable runway to manage risks and implement its improvement plan
1. Includes restricted cash of $21 million and $32 million as of Sept. 30, 2015 and Feb. 25, 2016.
2. Represents total principal balance outstanding. The issuance of the Exchange Term Loan and related repurchases of 2018 Notes and 2022 Notes were accounted for in accordance with FASB ASC 470-60, Troubled Debt Restructuring by Debtors ("ASC 470-60). EXCO determined that the future undiscounted cash flows from the Exchange Term Loan through its maturity were less than the carrying amounts of the retired 2018 Notes and 2022 Notes. As a result, the Company adjusted its carrying amount of the Exchange Term Loan to equal the total future cash payments, including interest and principal. Subsequently, all cash payments under the terms of the Exchange Term Loan, whether designated as interest or as principal amount, will reduce the carrying amount and no interest expense will be recognized. The undiscounted future interest payments on the Exchange Term Loan expected to be due in 2016 are classified as Current portion of long-term debt on the balance sheet. As such, the Company's reported interest expense will be less than the contractual payments throughout the term of the Exchange
Term Loan. 4

ETX & NLA Gross Transportation Commitments
16; $MM
1
’15 & Early ’16 Accomplishments
• Renegotiated North Louisiana transportation contracts realizing annual savings of ~$10MM
• Negotiated South Texas sales agreement and improved wellhead differential
2
31
42
1
53
126
2
3
4
’16 Focus
• Market unutilized portion of transportation to increase utilization
• Evaluate M&A transactions to increase utilization
• Continue to blend and extend gathering and transportation contracts
• Evaluate options to issue secured debt in exchange for cost relief
• Consider other commercial/legal options
3
1. Assumes estimated market value of $0.10/MMBtu for transportation and elimination of unused commitments.
2. Represents the difference between the contracted rates and the estimated market value of $0.10/MMBtu.
3. Represents estimated unused commitments at estimated market value of $0.10/MMBtu.
4. Gross amount due before any legally permitted sharing of costs with third parties.
5

G&A Reduction
15-16; Mixed Measures
Unit
’15 Run Rate Pre Q4
Headcount Reduction 1
’15 Run Rate Post Q4
Headcount Reduction 2
1
’16 Run Rate Target 3
Annualized Cash
G&A $MM 57 34 25
G&A/’15 EBITDA 4 Quartile Third Quartile First Quartile Top Decile
G&A/Total Entity
Value 4 Quartile Third Quartile First Quartile
1. Represents Q3 ‘15 GAAP G&A of $13MM annualized and adjusted to include $7MM of capitalized salaries and exclude $4MM of non-cash equity based compensation.
2. Represents Q4 ‘15 GAAP G&A of $18MM annualized and adjusted to include $6MM of capitalized salaries and exclude $13MM of non-cash equity based compensation and $11MM of severance and further adjusted for the reduction in headcount.
3. Targeted GAAP G&A plus capitalized salaries of $5MM and minus non-cash equity based compensation.
4. Source Capital IQ as of 11/7/15.
Top Decile
6

ETX Drilling Days Versus Depth
15; ft, Days
0
5,000
10,000
15,000
20,000
0
Well A
Well E
10
Well B
Well F
20
AFE 46 Days
AVG 39 Days
30
Well C
AFE Well
1
40
Well D
50
NLA Drilling Days Versus Depth
16; ft, Days
0
5,000
AFE 31 Days
AVG 26 Days
10,000
15,000
0
AFE Well
10
Well A
20
Well B
30
Well C
40
2
ETXNLA Well Cost Reduction
15-16; %
Completion
& Rentals
Drilling Rig &
Mobilization
Drilling
Rentals Tubulars
-56%
-31%
-27%
-24%
Fuel, Mud &
Chemicals
3
Directional
Services
-21% -21%
Well Delivery And Cost Strategy
4
• Measure progress, post appraisal of results, refine procedures
• Record NLA well in 23 days, best drilling performance in company history
• Work with service providers, to increase efficiencies, negotiate contracts and pricing to align with development program
• Supply chain/operations process provides most cost effective solution
Current wells drilled in record time with overall drilling and completion costs down 28%
7

Capital Program Overview
16; Mixed Measures
1
Capital Budget By Type
16; $MM
2
Category
Category Descriptions
Approved
$103MM ‘16
Capital
Program
1H ‘16
Development
Activity
• $70MM for drilling activity through Jun
‘16 and completion activity through
Aug ‘16
• $33MM field, land and capitalized costs for full-year ’16
• Two rig program focused on natural gas opportunities in NLA
• Drill and complete 9.0 gross (5.5 net) wells in NLA
• Complete 9 carry in wells (4.1 net) in
ETX
• Program appraises new areas and design improvements
• No drilling activity in ETX, STX or
Appalachia
2H ‘16 Plans • Evaluate 2H ‘16 drilling plans
• Will modify development plans based on returns to preserve liquidity and capital resources in preparation for future growth
Drilling and Completion (Jan ‘16 – Aug ’16)
Field Operations and Non-Operated (FY ‘16)
Land (FY ‘16)
Capitalized Costs (FY ‘16)
Total
Development Capital Spending By Area
Jan ’16-Aug ‘16; Mixed Measures
Area
Gross
Spuds
#
Net
Spuds
#
Net
Completions
#
East TX
North LA
Total
0
9
9
0
5.5
5.5
4.1
5.5
9.6
70
13
6
14
103
3
D&C
Capital
$MM
28
42
70
1H ’16 Drilling and Completion Budget of $70MM Represents a Reduction of $101MM, or 59%, Versus ‘15 Comparable Period
8

SEC Proved Reserves 1
15; Mixed Measures
1P Reserves By Area (907 Bcfe)
STX
APP
52
129
NLA
485
ETX
240
1P SEC PV-10 By Area ($402MM)
STX
$207
APP
$6 NLA
$91
ETX
$98
1P Reserves By Commodity
Oil
14%
Gas
86%
1
Proved Reserves PV-10
15; $MM
2
SEC Proved Reserves Reconciliation
14-15; Natural Gas Equivalent; Bcfe
3
198
3
184
(616)
(2)
(124)
811
1,264
402
907
SEC 1 NYMEX 2
Q4 '14 Proved
Reserves
Extensions &
Discoveries
Acquisitions Revisions -
Performance
Revisions -
Price
Divestitures Production Q4 '15 Proved
Reserves
1. The Total Proved Reserves as of Dec 31, 2015 were prepared in accordance with the rules and regulations of the SEC. The reserves were prepared using reference prices of $2.59 per Mmbtu for natural gas and $50.28 per Bbl for oil, in each case adjusted for geographical and historical differentials.
2. NYMEX Total Proved Reserves as of Dec 31, 2015 based on Dec 31, 2015 NYMEX pricing of $2.49, $2.79, $2.91, $3.03, $3.18, $3.46, $3.61, $3.74, $3.88 per Mcf and $41.44, $46.47, $49.70, $52.19, $53.77, $54.75, $55.29, $55.71, $57,50 per Bbl for 2016 through 2025 with terminal pricing of $4.00/Mcf and $57.50/Bbl.
9

Debt Principal And Liquidity
4Q 15; Mixed Measures
Factors
Debt Schedule
Cash And Restricted Cash 1
Credit Agreement
2 nd Lien Term Loans 2
18 Senior Notes
22 Senior Notes
Total Debt 2
Net Debt 2
Liquidity
Unit
$MM
$MM
$MM
$MM
$MM
$MM
$MM
1
4Q 15
Actual
33
67
700
158
223
1,148
1,115
Debt Principal Maturity Profile As Of Feb. ‘16
16-22; $MM
95
149
16 17
Unsecured Notes
18
700
183
19
Second Lien
20 21 22
Credit Agreement
2
Letters Of Credit
Available For Borrowing
Cash And Restricted Cash 1
$MM
$MM
$MM
$MM
$MM
375
3
7
301
33
Liquidity And Capital
14-15; Mixed Measures
Factors Unit
4Q 15
Actual
3
4Q 14
Actual
Liquidity $MM 334 Liquidity $MM 334 761
Key Metrics
Capital Budget $MM 103 277
Adjusted EBITDA 3 /Interest 4 x 2.38
Secured Debt 2 /LTM Adjusted EBITDA 3,4 x 0.28
Capital Budget/Liquidity % 30 36
Net Debt 2 /LTM Adjusted EBITDA 3 x 4.68 Forward 12 Commodity Price $/Mmbtu 2.11 3.04
1. Includes restricted cash of $21 million as of Dec 31, 2015.
2. Represents total principal balance outstanding. The issuance of the Exchange Term Loan and related repurchases of 2018 Notes and 2022 Notes were accounted for in accordance with FASB ASC 470-60, Troubled Debt Restructuring by Debtors ("ASC 470-60). EXCO determined that the future undiscounted cash flows from the Exchange Term Loan through its maturity were less than the carrying amounts of the retired 2018 Notes and 2022 Notes. As a result, the Company adjusted its carrying amount of the Exchange Term Loan to equal the total future cash payments, including interest and principal. Subsequently, all cash payments under the terms of the Exchange Term Loan, whether designated as interest or as principal amount, will reduce the carrying amount and no interest expense will be recognized. The undiscounted future interest payments on the Exchange Term Loan expected to be due in 2016 are classified as Current portion of long-term debt on the balance sheet. As such, the Company's reported interest expense will be less than the contractual payments throughout the term of the Exchange
Term Loan.
3. Adjusted EBITDA is a non-GAAP measure. See appendix for definition and reconciliation.
4. These ratios differ in certain respects from the calculations of comparable measures in the Credit Agreement. As of Dec 31, 2015, the ratio of consolidated EBITDAX to consolidated interest expense (as defined in the agreement including interest expense calculated in accordance with GAAP) was 2.4 to 1.0 and the ratio of senior secured indebtedness (excluding the Second Lien Term Loans) to consolidated EBITDAX (as defined in the agreement) was 0.3 to 1.0.
10

Factors
Rig Count
Net Wells Drilled
Net Wells Turned To Sales
Production
Oil
Natural Gas
Total
Total Daily
Realized Price Differentials
Oil
Natural Gas
Financial Results
Lease Operating Expense
Production Taxes
Gathering And Transportation
General And Administrative
Cash Interest Expense
Adjusted EBITDA 3
Capital Expenditures
2
1
Unit
#
#
#
Mbbl
Bcf
Bcfe
Mmcfe/d
$/Bbl
$/Mcf
$/Mcfe
$/Mcfe
$/Mcfe
$MM
$MM
$MM
$MM
4Q 15
Actual
3
2.7
4.3
609
25.7
29.3
319
(4.57)
(0.65)
0.41
0.21
0.86
14
21
50
35
Three Months Ended
3Q 15
Actual % Change
4 (25)
5.2
4.6
635
27.5
31.3
340
(3.37)
(0.73)
0.40
0.19
0.76
12
27
62
64
(48)
(7)
(4)
(7)
(6)
(6)
36
(11)
3
11
13
17
(22)
(19)
(45)
527
28.1
31.3
340
(2.34)
(0.82)
0.50
0.22
0.80
14
26
81
122
4Q 14
Actual % Change
7 (57)
9.4
11.6
(71)
(63)
16
(9)
(6)
(6)
95
(21)
(18)
(5)
8
-
(19)
(38)
(71)
Twelve Months Ended
12/31/15
Actual
4
17.8
29.2
2,342
109.9
124.0
340
(4.78)
(0.62)
0.43
0.18
0.80
52
101
238
277
Actual
9
41.4
29.6
2,236
122.3
135.7
372
(5.71)
(0.65)
0.47
0.22
0.75
61
102
391
424
12/31/14
% Change
(56)
(57)
(1)
5
(10)
(9)
(9)
(16)
(5)
(9)
(18)
7
(15)
(1)
(39)
(35)
1. Excludes equity-based compensation expenses of $3.2 million, $0.9 million and $0.6 million for the three months ended Dec 31, 2015, Sep 30, 2015 and Dec 31, 2014, respectively, and $7.2 million and $5.0 million for the years ended Dec 31, 2015 and 2014, respectively.
2. Cash interest expenses exclude the amortization of debt issuance costs, discount on notes and capitalized interest. In addition, cash payments under the Exchange Term Loan are not considered interest expense per ASC 470-60 and are excluded from the cash interest expenses amounts shown. EXCO's expected payments on the Exchange Term Loan in 2016 are $50.0 million.
3. Adjusted EBITDA is a non-GAAP measure. See appendix for definition and reconciliation. 11

Factors
Rig Count
Wells Drilled (Net)
Wells Turned To Sales (Net)
Production
Oil
Natural Gas
Total
Total Daily
Realized Price Differentials
Oil
Natural Gas
Financial Results
Lease Operating Expense
Production Taxes
Gathering And Transportation
General And Administrative
Cash Interest Expense 2
1
Unit
#
#
#
Mbbl
Bcf
Bcfe
Mmcfe/d
$/Bbl
$/Mcf
$/Mcfe
$/Mcfe
$/Mcfe
$MM
$MM
Three Months Ended
4Q 15 4Q 15 Guidance
Actual
3
2.7
4.3
609
25.7
29.3
319
(4.57)
(0.65)
0.41
0.21
0.86
14
21
Low
NA
NA
NA
655
25.1
29.0
315
(2.00)
(0.60)
0.40
0.15
0.80
11
28
High
675
25.9
29.9
325
(4.00)
(0.70)
0.45
0.20
0.85
13
30
Twelve Months Ended
12/31/15
Actual
4
17.8
29.2
2,342
109.9
124.0
340
(4.78)
(0.62)
0.43
0.18
0.80
52
101
12/31/15 Guidance
Low
4
17.6
29.3
2,300
108.5
122.3
335
(4.00)
(0.55)
0.40
0.15
0.80
48
109
High
2,400
111.5
125.9
345
(6.00)
(0.65)
0.45
0.20
0.85
52
114
1. Excludes equity based compensation expense.
2. Cash interest expenses exclude the amortization of debt issuance costs, discount on notes and capitalized interest. In addition, cash payments under the Exchange Term Loan are not considered interest expense per ASC 470-60 and are excluded from the cash interest expenses amounts shown. EXCO's expected payments on the Exchange Term Loan in 2016 are $50.0 million. 12

Factors
Rig Count
Wells Drilled (Gross/Net)
Wells Turned To Sales (Gross/Net)
Production
Oil
Natural Gas
Total
Total Daily
Realized Price Differentials
Oil
Natural Gas
Financial Results
Lease Operating Expense
Production Taxes
Gathering And Transportation
General And Administrative
Cash Interest Expense 2
1
Unit
#
#
#
Mbbl
Bcf
Bcfe
Mmcfe/d
$/Bbl
$/Mcf
$/Mcfe
$/Mcfe
$/Mcfe
$MM
$MM
4Q 15
Actual
3
2.7
4.3
609
25.7
29.3
319
(4.57)
(0.65)
0.41
0.21
0.86
14
21
Low
5/4.3
8/3.6
525
23.2
26.4
290
(4.00)
(0.60)
0.40
0.15
0.90
7
17
2
Guidance
1Q 16
High
535
24.1
27.3
300
(6.00)
(0.70)
0.45
0.20
0.95
8
19
Low
2
4/3.0
6/5.1
460
25.0
27.8
305
(4.00)
(0.60)
0.40
0.15
0.90
5
17
2Q 16
High
480
25.8
28.7
315
(6.00)
(0.70)
0.45
0.20
0.95
6
19
1. Excludes equity based compensation expense.
2. Cash interest expenses exclude the amortization of debt issuance costs, discount on notes and capitalized interest. In addition, cash payments under the Exchange Term Loan are not considered interest expense per ASC 470-60 and are excluded from the cash interest expenses amounts shown. EXCO's expected payments on the Exchange Term Loan in 2016 are $50.0 million. 13

1
Factors
Natural Gas
Unit
Oil
Fixed Price Swaps - Henry Hub Bbtu, $/Mmbtu
Mbbl, $/Bbl Fixed Price Swaps - WTI
Percent Hedged 3
Natural Gas
Oil
%
%
Twelve Months Ended
12/31/16
Volume Price
Twelve Months Ended
12/31/17
Volume 2 Price
Twelve Months Ended
12/31/18
Volume Price
53,670
915
73
42
2.90
61.89
20,050
-
39
-
3.01
-
3,650
-
9
-
3.15
-
1. Includes contracts entered into as of Feb 23, 2016.
2. Includes 7,300 Bbtu of swaptions.
3. Percent hedged based PDP production forecast. 14

Operating Area Overview
East Texas And North Louisiana
Net Acres/%HBP 1
Q4 ‘15 Operated Rigs
Q4 ‘15 Net Production (Mmcfe/d)
Year End Proved Reserves (Bcfe) 2
South Texas
Net Acres/% HBP 1
Q4 ‘15 Operated Rigs
Q4 ‘15 Net Production (Boe/d)
Year End Proved Reserves (Bcfe) 2
Appalachia And Other
Net Acres/% HBP 1
Q4 ‘15 Operated Rigs
Q4 ‘15 Net Production (Mmcfe/d) 3
Year End Proved Reserves (Bcfe) 2
Total
Net Acres/% HBP 1
Q4 ‘15 Operated Rigs
Q4 ‘15 Net Production (Mmcfe/d)
Year End Proved Reserves (Bcfe) 2
1
97,600/96%
3
238
726
65,800/81%
0
7,300
129
272,800/87%
0
37
52
436,200/88%
3
319
907
Core Basins
Net Production 3
13-15; Mmcfe/d
2
3
394 392
441 420
380 358
333 331 339
361 340
319
Q1
13
South Texas
Q2
13
Q3
13
Q4
13
East Texas /
North Louisiana
Q1
14
Q2
14
Appalachia
Q3
14
Q4
14
Q1
15
Q2
15
Q3
15
Q4
15
1. Net acres as of Dec 31, 2015.
2. The Total Proved Reserves as of Dec 31, 2015 were prepared in accordance with the rules and regulations of the SEC. The reserves were prepared using reference prices of $2.59 per Mmbtu for natural gas and $50.28 per Bbl for oil, in each case adjusted for geographical and historical differentials.
3. Shut-in 11 Mmcfe/d of production in Q4.
4. Net production excludes production from divested assets.
16

Operating Area Overview
Attribute
Total Acreage
Active Wells
Production
Targeted
Formations
Q4 ‘15 Results
1
Key Features
• 46,100 net acres (45,800 shale)
• 88% HBP
• 97 wells flowing to sales
• Q4 ‘15: 64 Mmcfe/d
• Haynesville
• Bossier
• Produced 64 Mmcfe/d, an increase of 12
Mmcfe/d, or 23%, from Q3 ’15
• Drilled 6 gross (2.7 net) and turned-to-sales
4 gross (2.0 net) operated Haynesville and
Bossier wells in Q4 ’15
• Increased undeveloped proved reserves per
1,000’ of lateral to 1.5 Bcf from 1.3 Bcf
• Nacogdoches County well continues to exceed expectations; opportunity to unlock
112 undeveloped locations in the area
Area Of Operations
Net Production
13-15; Mmcfe/d
43
37
30
25 22 22 25
47 45
40
52
2
3
64
Q1
13
Q2
13
Q3
13
Q4
13
Q1
14
Q2
14
Q3
14
Q4
14
Q1
15
Q2
15
Q3
15
Q4
15
17

East Texas Lateral Length And Days To Drill
10-16E; ft; Days 2
8,0 00
Days to drill
59
7,0 00
54
52
47
6,0 00
43
46
5,0 00
4,0 00
6,520
6,841
7,500
30
40
70
60
50
3,0 00
4,717 4,675
5,090
2,0 00
20
1
10
1,0 00
0
10 11 12 14
East Texas Drilling Cost Per Foot
10-16E; $/ft 1,2
15 Current
0
3
East Texas D&C Cost Per Lateral Foot
10-16E; $/ft 1,2
3,011
2,870
2,193
1,910
1,461
1,341
10 11 12 14
East Texas Proppant Per Lateral Foot
10-16E; lbs/ft 2
15 Current
2
4
348
360
316
270
236
201
10 11 12 14
1. Based on Haynesville well cost.
2. 2015 is an average of seven wells with increased completions greater than 2,100 lbs/ft.
15 Current
800
10
850
11
2,530
2,700
950
1,400
12 14 15 Current
18

Operating Area Overview
Attribute
Total Acreage
Active Wells
Key Features
• 51,500 net acres (38,000 shale)
• 100% HBP
• 413 wells flowing to sales
Production
Targeted
Formations
Q4 ‘15 Results
1
Area Of Operations
2
• Q4 ‘15: 174 Mmcfe/d
• Haynesville
• Bossier
• Produced 174 Mmcfe/d, a decrease of 23
Mmcfe/d, or 12%, from Q3 ’15
• No development activity during Q4 ‘15
• Increased undeveloped proved reserves per
1,000’ of lateral to 2.0 Bcf from 1.6 Bcf in the core area
• Implemented several initiatives to enhance and manage base production and reduce gathering system pressure
Net Production
13-15; Mmcfe/d
3
329
291
310
286
259
235
217
193 207
231
197
174
Q1
13
Q2
13
Q3
13
Q4
13
Q1
14
Q2
14
Q3
14
Q4
14
Q1
15
Q2
15
Q3
15
Q4
15
19

North Louisiana Lateral Length And Days To Drill
10-16E; ft, Days
47
4,6 00
Days to drill
41
4,5 00
37
35
37
4,4 00
32
31
4,3 00
50
45
40
35
1
30
4,2 00
4,500
20
25
4,1 00
4,346
4,0 00
4,219 4,213 4,258
4,264
15
3,8 00
3,9 00
4,019
10
5
3,7 00
10 11 12 13 14 15 Current
0
North Louisiana Drilling Cost Per Foot
10-16E; $/ft
3
North Louisiana D&C Cost Per Lateral Foot
10-16E; $/ft
2,742
2,375
1,971
1,643 1,765 1,664 1,415
2
10 11 12 13 14 15 Current
North Louisiana Proppant Per Lateral Foot
10-16E; lbs/ft
4
294 289
278
254 255
234
189
10 11 12 13 14 15 Current
2,700
1,200
900
750 800
1,600 1,650
10 11 12 13 14 15 Current
20

Operating Area Overview
1
Attribute
Total Acreage
Key Features
• 65,800 net acres
• 81% HBP (100% Core)
Active Wells • 235 wells
Production
Targeted
Formations
•
•
• Q4 ‘15: 7.3 MBoe/d
Eagle Ford
Buda
Q3 ‘15 Results And
Remaining ‘15
Development Plan
• Produced 7.3 Mboe/d consistent with Q3
’15
• Turned-to-sales 3 gross (1.8 net) operated wells in Q4 ’15
• Initial production rates averaged 780 Bbls/d for the 3 wells turned-to-sales
• Acreage position is largely held-byproduction, providing flexibility in timing of development
Area Of Operations
Net Production
13-15; Boe/d
2
3
6,200
7,100
6,500 6,500
5,900 6,100 6,000
7,200 7,300 7,300
Q3 13 Q4 13 Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15
21

Operating Area Overview
Attribute
Total Acreage
Active Wells
Production
Targeted
Formations
Q4 ‘15 Results
Key Features
• 269,800 net acres (137,400 shale)
• 84% HBP (shale)
• 126 Marcellus flowing to sales
• 5,509 conventional flowing to sales
• Q4 ‘15: 37 Mmcfe/d
• Marcellus
• Utica and Upper Devonian
• Produced 37 Mmcfe/d, a decrease of 10
Mmcfe/d, or 21% from Q3 ’15
• Elected to shut-in 11 Mmcfe/d during Q4
‘15 due to low commodity prices
• Turned-to-sales 1 gross (0.5 net) operated well in Q4 ’15
• Reduction in force during Q4 ‘15 reduced headcount by 41% in the region to better align operations personnel and reduce costs
1
Area Of Operations
Q1
13
Q2
13
Q3
13
Q4
13
Q1
14
Q2
14
Q3
14
Q4
14
Q1
15
Q2
15
Q3
15
Q4
15
2
Net Production
13-15; Mmcfe/d
64 64 66 61 62
56 56 55
51
47 47
3
37
22

1
2
3
Target Lateral Length
Gross Locations
Net Locations
4
5
6
WI
NRI
Spacing
Type Curve
7
8
9
IP
Phase I – Duration Month
Phase I – B Factor
10 Phase I – Initial Decline
11 Phase II – Duration Month
12 Phase II – B Factor
13 Phase II – Initial Decline
14 Phase III – Initial Decline
15 Terminal Decline
16 Wellhead EUR
17 EUR per 1,000’ (lateral length)
18 D&C
19 LOE Fixed
20 Variable/Gathering Expense
Single Well Returns
21 Breakeven Flat Price (25% IRR)
Mcf/d
Month x
%
Month x
%
%
%
Bcf/Mbo
Bcf or Mbo
$MM
$/month
$/Mcf
$/Mcf
Unit
Ft
#
#
%
%
Acres
ETX
Shelby HSVL
7,500
75
31
41
31
207
9,400
14
0.6
22
7
0.6
42
33
6
13.0
1.75
10.1
2,866
0.03/0.27
2.82
9,400
14
0.6
22
7
0.6
42
33
6
13.0
1.75
10.5
2,866
0.03/0.27
2.93
ETX
Shelby
Bossier
7,500
101
43
43
33
207
NLA
DeSoto Core
4,500
33
16
47
36
136
16,000
16
0.0
60 n/a
1.0
57.1 n/a
6
9.5
2.1
6.4
2,465
0.01/0.42
2.35
23

24

This presentation contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. These forward-looking statements relate to, among other things, the following:
 future financial and operating performance and results;
 business strategy;
 market prices;
 future use of derivative financial instruments; and
 plans and forecasts.
The Company based these forward-looking statements on current assumptions, expectations and projections about future events.
The Company uses the words “may,” “expect,” “anticipate,” “estimate,” “believe,” “continue,” “intend,” “plan,” “potential,” "project," “budget” and other similar words to identify forward-looking statements. The statements that contain these words should be read carefully because they discuss future expectations, contain projections of results of operations or financial condition and/or state other “forward-looking” information. The Company does not undertake any obligation to update or revise any forward-looking statements, except as required by applicable securities laws. These statements also involve risks and uncertainties that could cause actual results or financial condition to materially differ from expectations in this presentation, including, but not limited to:
 fluctuations in the prices of oil and natural gas;
 the availability of oil and natural gas;
 future capital requirements and availability of financing, including limitations on our ability to incur certain types of indebtedness under our debt agreements;
 our ability to meet our current and future debt service obligations, including our ability to maintain compliance with our debt covenants;
 disruption of credit and capital markets and the ability of financial institutions to honor their commitments;
 estimates of reserves and economic assumptions, including estimates related to acquisitions and dispositions of oil and natural gas properties;
 geological concentration of our reserves;
 risks associated with drilling and operating wells;
 exploratory risks, including those related to our activities in shale formations;
 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;
 availability of water and other materials for drilling and completion activities;
 marketing of oil and natural gas;
 political and economic conditions and events in oil-producing and natural gas-producing countries;
 title to our properties;
 litigation;
 competition;
 our ability to attract and retain key personnel;
 general economic conditions, including costs associated with drilling and operations of our properties;
 our ability to comply with the listing requirements of, and maintain the listing of our common shares on, the New York Stock Exchange ("NYSE");
 environmental or other governmental regulations, including legislation to reduce emissions of greenhouse gases, legislation of derivative financial instruments, regulation of hydraulic fracture stimulation and elimination of income tax incentives available to our industry;
 receipt and collectability 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;
 our ability to manage joint ventures with third parties, including the resolution of any material disagreements and our partners’ ability to satisfy obligations under these arrangements;
 actions of third party co-owners of interests in properties in which we also own an interest;
 fluctuations in interest rates;
 our ability to effectively integrate companies and properties that we acquire; and
 our ability to execute the business strategies and other corporate actions developed in connection with EXCO's strategic improvement plan.
It is important to communicate expectations of future performance to investors. However, events may occur in the future that EXCO is unable to accurately predict, or over which EXCO has no control. Users of the financial statements are cautioned not to place undue reliance on a forward-looking statement. Any number of factors could cause actual results to differ materially from those in EXCO's forward-looking statements, including, but not limited to, the volatility of oil and natural gas prices, future capital requirements and the availability of capital and financing, uncertainties about reserve estimates, the outcome of future drilling activity, environmental risks and regulatory changes. Declines in oil or natural gas prices may have a material adverse effect on EXCO's financial condition, liquidity, results of operations, ability to fund operations and the amount of oil or natural gas that can be produced economically. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. EXCO undertakes no obligation to publicly update or revise any forward-looking statements. When considering EXCO's forward-looking statements, investors are urged to read the cautionary statements and the risk factors included in EXCO's Annual Report on Form 10-K for the year ended
December 31, 2014, filed with the Securities and Exchange Commission ("SEC") on February 25, 2015, as amended by Amendment No. 1 to Annual Report on Form 10-K/A filed with the SEC on April 10, 2015, and after March 2, 2016, EXCO's Annual Report on Form 10-K for the year ended December 31, 2015, and its other periodic filings with the SEC.
Revenues, operating results and financial condition substantially depend on prevailing prices for oil and natural gas and the availability of capital. Declines in oil or natural gas prices may have a material adverse effect on financial condition, liquidity, results of operations, the amount of oil or natural gas that we can produce economically and the ability to fund operations. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.
25