Investor Presentation September 2016 Exhibit 99.1

Forward Looking Statements 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 reductions to our borrowing base and 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, including restructuring our balance sheet and gathering and transportation contracts 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, 2015, filed with the Securities and Exchange Commission ("SEC") on March 2, 2016 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.

Agenda Haynesville Transformation Appendix EXCO Overview Executive Summary

EXCO Overview: Three Concentrated Shale Resource Positions Overview 1 Core Basins 2 Net Production3 13-16; Mmcfe/d 3 Acreage as of July 31,2016. Based on ten year June 30, 2016 strip prices and pro forma for recent divestiture of assets in Pennsylvania and STX settlement Net production excludes production from divested assets. Appalachia South Texas East Texas / North Louisiana Attribute Key Features Net Acres1 353,350 net acres 89% HBP Net Production Q2 ‘16: 296 Mmcfe/d Proved Reserves2 1.5 Tcfe $1.2B PV-10 Key Credit Highlights EXCO Resources (NYSE: XCO) is a Dallas based E&P company with a focus on shale resource plays in Louisiana, Texas and the Appalachia region Proven track record of high performance drilling and completion 222 employees Well situated, highly economic positions across multiple basins Deep, multi-year inventory with 643 gross (240 net) drilling locations that achieve greater than 20% IRR at current prices2 Highly successful at reducing D&C and operating costs and eliminating overhead Strong management team and sponsors Substantial 1st lien asset coverage

$1B+ Of Gas Focused Pro Forma Proved Reserves As Of June 30, 2016 With High Percentage Of PDP 1P PV-10 By Area; % 1 1P PV-10 By Category; % 2 1P PV-10 By Commodity; % 3 1P NYMEX Reserves Breakdown1 Jun 30, 2016; Mixed Measures 4 Note: Reserves are pro forma for recent divestitures and assumes capital budget exists to fund development of PUDs. 1. Based on ten year June 30, 2016 strip prices. 2. Represents management’s estimate of the total marketing and transportation liability net to EXCO. Effective January 1, 2017. Net Wells Oil Gas Gas Equivalent Gas Equivalent Pre Tax PV-10 # Mbbls MMcf MMcfe % $MM PDP 963 11,650 518,564 588,462 38 735 PNP/PBP 3 2 11,470 11,483 1 8 PUD 147 9,423 866,910 923,446 61 442 Proved Reserves 1,113 21,075 1,396,944 1,523,391 100 1,185 Marketing & Transport2 (223) Proved Reserves Less Marketing & Transport 1,113 21,075 1,396,944 1,523,391 100 962 EXCO’s Pre Tax Strip PV-10 has increased by 46% since year end 2015

EXCO Pro Forma Capitalization Includes $25.4mm of restricted cash. See appendix for further detail on restricted cash components. FactSet as of 7/31/16. Liquidity reflects $10.2mm in Letters of Credit.

ETX/NLA Gross Transportation Commitments 16; $MM 1 Execution Strategy 2 The Company is engaging its midstream and transportation providers to restructure these commitments More must be done to restructure contracts; opportunities include: 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 options Restructure Gathering And Transportation Contracts To Enhance Liquidity Assumes estimated market value of $0.10/MMBtu for transportation and elimination of unused commitments. Represents the difference between the contracted rates and the estimated market value of $0.10/MMBtu. Represents estimated unused commitments at estimated market value of $0.10/MMBtu. Gross amount due before any legally permitted sharing of costs with third parties. 1 2 3 4 Out-of-market gathering and transportation contracts are an overwhelming burden to EXCO and negatively impact the Company’s structural liquidity

Contractual Obligations And Commercial Commitments Contractual Obligations and Commercial Commitments 16 – 20 and Thereafter; $M 1 Contractual Obligations and Commercial Commitments 16 – 20 and Thereafter; $M 2 Gathering minimum volume commitments Marketing and transportation minimum volume commitments Other fixed commitments Drilling contracts Operating leases and other Total 2016 43,920 76,494 13,253 14,997 5,456 154,120 2017 43,800 76,285 5,443 7,284 4,228 137,040 2018 40,080 76,285 3,210 - 3,240 122,815 2019 - 76,285 2,403 - 3,053 81,741 2020 - 48,148 1,932 - 1,560 51,640 Thereafter - 135,943 1,599 - 72 137,614 Total 127,800 489,440 27,840 22,281 17,609 684,970 Note: Data represents contractual obligations and commercial commitments as of December 31, 2015 and does not include those related to equity method investments.

LOE By Quarter 15-16; $MM 1 Headcount Reduction 15-16; Mixed Measures 2 Reduce LOE And G&A Load To Reduce Fixed Cost Burden 47% LOE Reduction Since Q1 15 60% Headcount Reduction Since Q1 15 $44MM1 G&A Run Rate $29MM2 G&A Run Rate Represents Q1 ‘15 GAAP G&A of $15.2MM adjusted to exclude $1.7mm of equity based compensation and $2.6mm of severance, annualized. Represents Q2 ‘16 GAAP G&A of $17.0MM adjusted to exclude $9.3mm of equity based compensation and $0.5mm of severance, annualized. Headcount as of January 1, 2015. The company continues to rationalize its costs as part of its restructuring efforts

Agenda Haynesville Transformation Appendix EXCO Overview Executive Summary

EXCO Haynesville Relative Positioning EXCO Haynesville Relative Positioning 1 Haynesville Shale Area Map 2 Source: IHS Performance Evaluator, investor presentations and company information. Horizontal wells with a first production date between 1/1/12 – 4/1/16 targeting Haynesville and Bossier horizons shown on map. Established, world class gas play with significant well and seismic control allows for comprehensive understanding of reservoir dynamics and geological characteristics Proven large volume frac completion techniques generate EURs that more than double early well performance play results with substantially reduced costs have effectively re-rated the shale gas play’s economics De-risked resource, highly delineated trend areas offer substantial proved reserves and repeatable opportunity set under favorable economic risk-reward scenarios Strong breakeven (IRR 25%) prices under $2.70 / Mmbtu that can compete with Appalachian shale gas plays in a differentiated U.S. region Located in an industry friendly regulatory environment allowing for better program development execution Existing midstream infrastructure in place with premium geographical access to LNG terminals and developing demand centers Drilling and completion costs have steadily decreased over the years with continuously demonstrated improvement Well positioned for a long-term rebound on gas prices and / or gas exports from the Gulf Coast Haynesville Core Haynesville Shale EXCO BHP Chesapeake Comstock Covey Park (EP) EOG Exxon GeoSouthern (ECA) QEP Vine TX LA EXCO acreage

On-going New Completion Designs And Refrac Opportunities Are Re-Rating Play Proppant to Mcf Breakdown 1 Haynesville Re-Frac Analysis 2 The play has been economically re-rated through the application of modern completion designs using lessons learned from other resource plays and also benefitting from extensive technical and reservoir information Drilling and completion designs have evolved into larger wells and larger frac jobs with increasing EURs Larger fracs, longer laterals and wider spacing has increased the certainty of results and enhanced the inventory of economic opportunities Systematic new completion trials have been tested on the play by EXCO and several other operators in the core area have validated their results Source: RRC. Note that horizontal wells with a first production date between 1/1/13 – 4/1/16 targeting Haynesville and Bossier horizons with a lateral length of 3,000' or greater. Operators in the play have engaged in a re-frac campaign to optimize completions from existing wells several years old with new technology and understanding developed over the last five years of intense shale development in the U.S. Diagnostic results have indicated that an average of 1/3 of the lateral is effectively stimulated by modern re-fracs Allows for a significant production uplift opportunity in the future EXCO has inventory of ~270 re-fracs Restimulation of producing wells through offset new well completions supports the re-frac concept, as producing wells have realized 3x or more production enhancement Key Takeaways 3 Key Takeaways 4

North Louisiana Holly Offset Well Results Activity Summary 1 Activity Map 2 Net Production 2013-2015, Mmcfe/d 3 Well Name Operator Lat. Length 3 Months Cum Prod 6 Months Cum Prod Proppant Ft Mmcf / ‘000ft Mmcf / ‘000ft lbs/ft EXCO Holly Type Curve (EUR 2.1 Bcf/’000ft) EXCO 4,500 290 521 2,700 1 Whitaker 9-4 HC 2 EXCO 7,596 N/A N/A 2,763 2 Old Farms 1-1 ALT EXCO 4,182 N/A N/A 2,758 3 Gray 1-2 ALT EXCO 4,253 N/A N/A 2,755 4 Akin 4-9 HC 1 EXCO 7,666 N/A N/A 2,632 5 BRP 1-1 ALT EXCO 4,299 N/A N/A 2,560 6 Whitaker 9-4 HC 1 EXCO 7,597 N/A N/A 2,553 7 Robertson Clay 14 2 ALT Vine 4,625 248 498 3,787 8 R P Oden Sr. 35-02 HC 1 ALT EP 7,633 168 318 3,495 9 R P Oden Sr. 35-26 HC 1 ALT EP 7,623 182 406 3,319 10 CA 12&13-15-15 HC 1H CHK 9,814 N/A N/A 3,000 11 EMW 29-32 HC 1 ALT BHP 5,299 165 336 2,988 12 Rocking G Farms 23 3 ALT Vine 4,781 206 334 2,966 13 EMW 29-32 HC 2 ALT BHP 5,421 117 193 2,948 14 Caraway Estate 20-29 HC 1 ALT CRK 5,953 194 347 2,912 15 Gamble 4-33 HC 1 ALT CRK 7,547 130 205 2,879 16 Lowrey 27 2 ALT EP 4,536 170 319 2,788 17 Harrison 30-19 1 ALT CRK 7,437 114 194 2,731 18 Pyle 6-7 1 ALT CRK 7,578 123 230 2,727 19 Shahan 5-8 1 ALT CRK 6,880 115 222 2,727 20 Holmes 29-32 HC 1 ALT CRK 7,334 121 231 2,721 21 PCK 13&24&25 HC 1H CHK 7,140 N/A N/A 2,700 22 Horn 8-17 2 ALT CRK 8,301 140 248 2,386 23 PKY 35&26&23-14-15 HC 2 ALT CHK 5,941 252 426 2,317 24 PKY 26&35-14-15 HC 3 ALT CHK 5,294 209 423 2,270 25 QP 3&34&27-12-12 1H ALT CHK 6,259 220 327 2,267 Multiple operators, including EXCO, have successfully utilized increased proppant loading to increase well productivity Source: IHS, PLS, rigdata.com, haynesvilleplay.com, public filings and company materials. < 2,300 2,300 to 2,600 2,600 to 2,900 Operator Wells Proppant (lbs/ft) EXCO BHP Chesapeake Covey Park (EP) 2,900 to 3,200 3,200+ Comstock Vine 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

EXCO’s Recent Results in North Louisiana Standard length laterals drilled in Q2 2016 set company records, averaging 25 days from spud to rig release Record low D&C cost of $5.8 mm/well for standard laterals First three long laterals averaged 43 days with expected D&C cost of $8.5 mm/well Long lateral program will be drilled with rigs that have 7,500 psi rated pumps to improve rate of penetration EXCO’s first three long laterals with ~2,700 lbs./ft. have IP’d ~21 Mmcf/d with ~7,900 psi flowing pressure, exceeding the company’s expectations Larger completion designs with 2,700 lbs./ft. are demonstrating breakthroughs in well performance Current type curve IP is 16 Mmcf/d Wells are guided to 20-25 psi/d pressure drop Key Takeaways 3 Key Takeaways 4 NLA Drilling Days Versus Depth 16; ft, Days 1 Cumulative Gas vs. Time 16; Cumulative Production, Days 2 Standard Average: 25.0 days Long Average: 42.7 days1 1. One cross-unit long lateral well experienced an exceptionally high number of MWD failures resulting in additional time on location.

Operational Highlights 1 Area Of Operations 2 Key Takeaways 3 The North Louisiana Bossier Test Was A Success And Provides Future Opportunity Potential Bossier “Pay” Acreage Key Developments Successfully completed and turned to sales the Branch Ranch 5-3 Bossier test well in January 2015 The new well was EXCO’s first operated Bossier shale well in North Louisiana since 2010 and utilized new rate restriction program and enhanced completion methods with standard lateral length The well is outperforming two previous Bossier wells with smaller completion designs 100% HBP position allows EXCO to defer development to high price environment EXCO’s inventory includes 168 gross Bossier locations utilizing 7,500’ lateral lengths Breakeven price of $3.02/Mcf Branch Ranch 5-3 Only three Bossier horizontal wells in EXCO NLA position Longer lateral design with larger completions will enhance economics in the Bossier, similar to the Haynesville Extensive infrastructure in place Large 168 well inventory

Agenda Haynesville Transformation Appendix EXCO Overview Executive Summary

EXCO Overview: Three Concentrated Shale Resource Positions Operating Area Overview 1 Core Basins 2 Net Production3 13-16; Mmcfe/d 3 As of July 31, 2016. Based on ten year June 30, 2016 strip prices and pro forma for recent divestiture of assets in Pennsylvania and STX settlement. Net production excludes production from divested assets. East Texas And North Louisiana (Haynesville and Bossier) Net Acres/%HBP1 97,300/88% Q2 ‘16 Operated Rigs (none currently) 1 Q2 ‘16 Net Production (Mmcfe/d) 222 6/30/16 Proved Reserves (Bcfe)2 1,101 South Texas (Eagle Ford) Net Acres/% HBP1 54,250/93% Q2 ‘16 Operated Rigs 0 Q2 ‘16 Net Production (Boe/d) 5,400 6/30/16 Proved Reserves (Bcfe)2 146 Appalachia And Other (Marcellus, Utica and Upper Devonian) Net Acres/% HBP1 201,800/89% Q2 ‘16 Operated Rigs 0 Q2 ‘16 Net Production (Mmcfe/d) 43 6/30/16 Proved Reserves (Bcfe)2 277 Total Net Acres/% HBP1 353,350/89% Q2 ‘16 Operated Rigs 1 Q2 ‘16 Net Production (Mmcfe/d) 296 6/30/16 Proved Reserves (Bcfe)2 1,523 R/P, years 14.1 EXCO is a leading shale producer that has drilled over 800 horizontal shale wells since 2008, participated in 269 horizontal wells operated by others and is well positioned to develop large inventory of 643 horizontal operated locations Appalachia South Texas East Texas / North Louisiana

Operating Area Overview 1 Area Of Operations 2 Net Production 13-16; Mmcfe/d 3 North Louisiana Overview Attribute Key Features Total Acreage1 51,500 net acres (38,000 shale) 100% HBP Active Wells 416 operated wells flowing to sales Production Q2 ‘16: 146 Mmcfe/d Targeted Formations Haynesville Bossier Highlights Leading Haynesville driller and producer in North Louisiana Unparalleled basin area knowledge Re-initiated drilling in the area in late 2015 Inventory of 265 (gross) immediately executable drilling projects On the forefront of re-frac application and emerging Bossier development Q2 ‘16 Results Drilled 1 gross (0.9 net) operated Haynesville well in Q2 ‘16 Turned-to-sales 3 gross (2.5 net) wells in the Haynesville shale with average costs of $5.8mm, a 22% decrease from prior year Record low well cost despite larger stimulation design of 2,700 lbs/ft The 3 wells turned to sales in Q2 ’16 have estimated ultimate recoveries (EUR) of 2.1 Bcf per 1,000 lateral ft As of July 31, 2016.

NLA Lateral Length And Days To Drill 10-16; ft, Days 1 NLA D&C Cost Per Lateral Foot 10-16; $/ft 2 NLA Drilling Cost Per Foot 10-16; $/ft 3 NLA Proppant Per Lateral Foot 10-16; lbs/ft 4 Improve Economics Through Disciplined Execution And Cost Reductions EXCO has a strong track record of reducing costs and improving operational efficiencies; recent long laterals are the lowest cost per lateral foot that EXCO has achieved in the play1 Standard Long Standard Lateral Long Lateral Standard Lateral Long Lateral Standard Lateral Long Lateral Standard Lateral Long Lateral NLA D&C cost of 1,120 $/ft.

Operating Area Overview 1 Area Of Operations 2 Net Production 13-16; Mmcfe/d 3 East Texas Overview Attribute Key Features Total Acreage1 45,800 net acres 74% HBP Active Wells 104 operated wells flowing to sales Production Q2 ‘16: 76 Mmcfe/d Targeted Formations Haynesville Bossier Highlights Transferred D&C expertise and capabilities to this area and re-engaged development activities in 2014 Developed an inventory of 291 (gross) high return drilling projects; these projects represent a significant component of EXCO’s near term growth engine Other operators in Shelby area are XTO and BP, both with current rig activity Larger stimulation design and modified well spacing have increased proved reserves from 1.3 to 1.5 Bcf per 1,000 lateral ft Q2 ‘16 Results Most recent two wells drilled and completed have estimated ultimate recoveries (EUR) in excess of 2.0 Bcf per 1,000 lateral ft As of July 31, 2016.

ETX Lateral Length And Days To Drill 10-16; ft; Days 1 ETX D&C Cost Per Lateral Foot 10-16; $/ft 2 ETX Drilling Cost Per Foot 10-16; $/ft 3 ETX Proppant Per Lateral Foot 10-16; lbs/ft 4 Improve Economics Through Disciplined Execution And Cost Reductions EXCO has a strong track record of reducing costs and improving operational efficiencies

Operating Area Overview 1 Area Of Operations 2 Net Production 13-16; Boe/d 3 South Texas Overview As of July 31, 2016. Attribute Key Features Total Acreage1 54,250 net acres 93% HBP Active Wells 235 operated wells Production Q2 ‘16: 5.4 MBoe/d Targeted Formations Eagle Ford Highlights HBP acreage preserves inventory of 87 (gross) drilling projects Q2 ‘16 Results No development activity during Q2 ’16 Re-engaging in STX with one rig program beginning in October Acreage position is largely held-by-production, providing flexibility in timing of development Transferred ~350 bbls/d through settlement agreement with a partner to allow for additional development flexibility and relieve certain obligations Transitioned from Tier 2 to Tier 1 Type Curve post recent non-core acreage divestiture and settlement agreement with JV partner Renegotiated contracts to reduce salt water disposal and chemical costs Improved realized price on oil production by $1.95 to $2.90 per Bbl through a bidding process with transportation providers

Operating Area Overview 1 Area Of Operations 2 Net Production 13-16; Mmcfe/d 3 Appalachia Overview Attribute Key Features Total Acreage1 201,800 net acres (130,400 shale) 89% HBP (shale) Active Wells 126 operated Marcellus wells flowing to sales 1,986 conventional wells flowing to sales Closed the sale of shallow conventional assets in Pennsylvania on July 1, ‘16, reducing conventional well count by 3,523 Production Q2 ‘16: 43 Mmcfe/d Targeted Formations Marcellus Utica and Upper Devonian Highlights High HBP percentage extends tenor of EXCO’s Marcellus and Utica gas option Divestment of high cost conventional properties lowers EXCO’s cost of carry Q2 ‘16 Results Acreage position in the Marcellus shale is approximately 89% held-by-production, providing flexibility in timing of development Reduced field employee count by 52% in conjunction with the July 1, ‘16 divestiture EXCO holds 40,000 net acres that are well positioned in the emerging Utica shale dry gas play As of July 31, 2016.

Agenda EXCO Overview Haynesville Transformation Executive Summary Appendix

Financial And Operational Results Excludes equity-based compensation expenses of $9.3 mm, $3.8 million and $1.4 mm for the three months ended June 30, ‘16, March 31, ‘16 and June 30, ‘15, respectively, and $13.1 mm and $3.1 mm for the six months ended June 30, ‘16 and June 30, ’15, respectively. 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 ‘16 total $50.0 million. Adjusted EBITDA is a non-GAAP measure. See appendix for definition and reconciliation. Factors Unit Quarter-to-Date Year-to-Date 2Q 16 1Q 16 2Q 15 2Q 16 2Q 15 Actual Actual % Change Actual % Change Actual Actual % Change Rig Count # 1 2 (50) 4 (75) 1 4 (75) Net Wells Drilled # 0.9 4.3 (79) 4.4 (80) 5.2 9.9 (47) Net Wells Turned To Sales # 2.5 3.6 (31) 5.7 (56) 6.1 20.3 (70) Production Oil Mbbl 447 550 (19) 594 (25) 997 1,098 (9) Natural Gas Bcf 24.3 23.5 3 29.3 (17) 47.8 56.8 (16) Total Bcfe 27.0 26.8 1 32.9 (18) 53.8 63.4 (15) Total Daily Mmcfe/d 296 295 0 361 (18) 296 350 (15) Realized Price Differentials Oil $/Bbl (5.04) (5.23) (4) (4.65) 8 (5.15) (5.71) (10) Natural Gas $/Mcf (0.46) (0.55) (16) (0.52) (12) (0.50) (0.56) (11) Financial Results Lease Operating Expense $/Mcfe 0.28 0.35 (20) 0.43 (35) 0.32 0.46 (30) Production Taxes $/Mcfe 0.18 0.17 6 0.17 6 0.18 0.17 6 Gathering And Transportation $/Mcfe 1.00 0.99 1 0.75 33 0.99 0.80 24 General And Administrative1 $MM 8 7 14 11 (27) 15 25 (40) Interest Expense2 $MM 17 17 0 27 (37) 35 53 (34) Adjusted EBITDA3 $MM 23 21 10 69 (67) 44 125 (65) Capital Expenditures $MM 19 37 (49) 75 (75) 56 178 (69)

Actuals To Guidance Comparison Excludes equity based compensation expense. 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 ‘16 are $50.0mm. Factors Unit Three Months Ended Full Year 2016 Guidance 2Q 16 2Q 16 Guidance 3Q 16 Guidance Actual Low High Low High Low High Rig Count (Gross) # 1 1 0 1 Wells Drilled (Gross/Net) # 1/0.9 1/0.9 0/0 7/5.4 Wells Turned To Sales (Gross/Net) # 3/2.5 6/5.6 3/2.7 15/9.0 Production Oil Mbbl 447 470 490 375 395 1,720 1,740 Natural Gas Bcf 24.3 24.5 25.3 23.0 23.9 92.2 99.4 Total Bcfe 27.0 27.3 28.2 25.3 26.2 102.5 109.8 Total Daily Mmcfe/d 296 300 310 275 285 280 300 Realized Price Differentials Oil $/Bbl (5.04) (4.00) (6.00) (3.00) (5.00) (3.50) (5.50) Natural Gas $/Mcf (0.46) (0.60) (0.70) (0.50) (0.60) (0.50) (0.60) Financial Results Lease Operating Expense $/Mcfe 0.28 0.35 0.40 0.35 0.40 0.35 0.40 Production Taxes $/Mcfe 0.18 0.15 0.20 0.15 0.20 0.15 0.20 Gathering And Transportation $/Mcfe 1.00 0.95 1.00 1.00 1.05 1.00 1.05 General And Administrative1 $MM 8 6 7 9 10 30 35 Interest Expense2 $MM 17 17 19 16 18 60 65

Hedge Positions (Including Trades Since June 30) Factors Unit Six Months Ended 12/31/16 Twelve Months Ended 12/31/17 Twelve Months Ended 12/31/18 Volume Price Volume Price Volume Price Natural Gas Fixed Price Swaps - Henry Hub Bbtu, $/Mmbtu 28,520 2.88 23,700 2.99 3,650 3.15 Fixed Price Swaptions - Henry Hub2 Bbtu, $/Mmbtu - - 7,300 2.76 - - Collars - Henry Hub Bbtu 10,950 Sold Call Options $/Mmbtu 3.28 Purchased Put Options $/Mmbtu 2.87 Oil Fixed Price Swaps - WTI Mbbl, $/Bbl 552 58.61 183 50.00 - - Percent Hedged1 Natural Gas % 66 66 9 Oil % 66 13 - Percent hedged based upon PDP production forecast and includes swaption volumes. Exercisable on December 22, ‘16.

Unit NLA DeSoto Core NLA Caddo X-Unit Lateral NLA Caddo Standard Lateral NLA Bossier X-Unit Lateral ETX Shelby HSVL ETX Shelby Bossier ETX Highlander STX Eagle Ford Core Tier 1 STX Eagle Ford Core Tier 2 1 Target Lateral Length Ft 4,500 7,500 4,500 7,500 7,500 7,500 6,500 7,500 7,500 2 Gross Locations # 24 52 21 168 71 97 123 49 38 3 Net Locations # 9 13 8 78 29 41 30 14 18 4 WI % 39 25 37 47 42 42 25 39 47 5 NRI % 30 19 29 37 32 32 19 31 35 6 Spacing Acres 136 227 136 227 207 207 224 172 172 Type Curve                   7 IP Mcf/d 16,000 16,000 12,000 10,000 9,400 9,400 11,500 500 420 8 Phase I – Duration Month Month 16 18 18 12 14 14 18 15 4 9 Phase I – B Factor x 0 0 0 0 0.6 0.6 0 1.25 1.25 10 Phase I – Initial Decline % 60 40 52 41 22 22 41 61 85 11 Phase II – Duration Month Month n/a n/a n/a n/a 7 7 n/a n/a 4 12 Phase II – B Factor x 1 1 1 1 0.6 0.6 1 1.25 1.25 13 Phase II – Initial Decline % 57.1 66.2 64.5 55 42 42 42.5 35 35 14 Phase III – Initial Decline % n/a n/a n/a n/a 33 33 n/a n/a 46.5 15 Terminal Decline % 6 6 6 6 6 6 6 6 6 16 Wellhead EUR Bcf/Mbo 9.5 12 7.2 9.6 13 13 13 535 392 17 EUR per 1,000’ (lateral length) Bcf or Mbo 2.1 1.6 1.6 1.28 1.75 1.75 2 71 52 18 D&C/Pumping Unit $MM 6.0 8.0 6.0 8.4 9.2 9.5 10.3 3.8/0.275 3.8/0.275 19 LOE Fixed - WI $/month 1,876 1,876 1,876 2,465 2,922 2,922 2,711 8,914 7,249 20 Variable/Gathering Expense - WI $/Mcf,$/Bbl .02/.44 .02/.44 .02/.44 .02/.44 0.03/0.29 0.03/0.29 0.02/0.31 0.03/0.0 0.16/0.0 Single Well Returns             21 PV10 (8/8ths)1 $MM 4.8 5.1 2.6 1.7 6.1 5.8 3.9 3.1 2.2 22 IRR1 % 87 63 48 20 42 39 27 49 35 23 Breakeven Flat Price (25% IRR) $/Mmbtu 2.19 2.35 2.53 3.02 2.62 2.70 3.02 44.25 47.00 24 PV/I, Disc X 1.81 1.64 1.44 1.20 1.67 1.62 1.38 1.76 1.56 Appendix: Single Well Economics – Internal Type Curves Economics based on June 30, 2016 strip prices through 2021 and held flat thereafter at $3.19 per Mcf for Henry Hub Natural Gas and $56.31 for WTI Oil.

Appendix: June 30, 2016 Price Deck Henry Hub Natural Gas Prices WTI Crude Oil Prices Year $/Mcf $/Bbl 2016 3.03 48.85 2017 3.18 52.40 2018 3.02 53.81 2019 3.00 54.69 2020 3.06 55.51 2021 3.19 56.31 2022 3.35 57.04 2023 3.53 57.86 2024 3.70 57.86 2025 3.88 57.86 Terminal 3.88 57.86

Appendix: Detailed Description of EXCO’s Restricted Cash Position EXCO’s Restricted Cash Position Restricted cash is principally comprised of EXCO’s share of an evergreen escrow account with BG Group/Shell that is used to fund the company’s share of development operations in East Texas and North Louisiana. Funds held in this escrow account are restricted and can be used primarily for drilling and operations in East Texas and North Louisiana. The restricted cash also includes accrued fees payable to Energy Strategic Advisory Services LLC ("ESAS") upon completion of its entire first year of service and required investment with EXCO.

EBITDA, Adjusted EBITDA, Adjusted Operating Cash Flow and Free Cash Flow Reconciliations