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EXCO RESOURCES, INC.

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SLIDE 1

First Quarter 2017 Review Hal Hickey Harold Jameson Tyler Farquharson Chief Executive Officer Chief Operating Officer Chief Financial Officer May 10, 2017

SLIDE 2

Strategic Plan Update Focus Area # Improvement Plan Update Liability Management 1 Improve Debt Structure To Provide Structural Liquidity Issued $300MM in new 1.5 Lien Notes and exchanged $683MM in existing 2nd Lien Term Loans for new 1.75 Lien Term Loans. These instruments allow for the Company to pay interest in either cash, common shares or additional debt Improved liquidity by $120 million in Q1 ‘17 compared to Q4 ‘16 through issuance of new indebtedness and exchange of existing indebtedness Credit Agreement amended to establish a borrowing base of $150MM (undrawn at March 31, ‘17); amendments allow for the issuance of 1.5 Lien Notes and 1.75 Lien Term Loans and modification of certain covenants Continuing to evaluate repurchases of 2018 and 2022 unsecured notes. The Company has $132MM outstanding on its 2018 Notes and $70MM outstanding on its 2022 Notes 2 Restructure Gathering And Transportation Contracts To Provide Liquidity Negotiating with midstream and transportation providers to restructure gathering and transportation contracts Operational Performance 3 Reduce LOE and G&A Load To Reduce Fixed Cost Burden Decreased LOE costs by 11% in Q1 ‘17 compared to Q4 ‘16 Reduced total employee headcount approximately 41% since Q1 ‘16 4 Improve Drilling And Completion Performance To Improve Capital Returns Enhanced completions in the Haynesville with 2,700 lbs/ft have improved EUR/ft to 2.3 Bcf/1,000 ft in NLA and to 2.6 Bcf/1,000 ft in ETX Company is implementing larger completion designs with higher fracture intensity and tighter cluster spacing in 2017, increasing proppant amount from 2,700 to 3,500 lbs/ft North LA Bossier appraisal test with long lateral and enhanced completion design recently TTS; plan to drill four additional Bossier appraisal wells in 2017 to evaluate opportunity and unlock upside Capital Deployment 5 Implement A “Liquidity Driven” Prioritized Capital Allocation System To Ensure Highest And Best Use Of Capital Increased ‘17 capital budget to $158MM versus capital spend of $78MM in ‘16 Measuring capital allocation decisions against liquidity intensity benchmark Executed agreement to sell South Texas asset. Proceeds from divestiture will primarily be deployed to high rate of return opportunities in the Haynesville and Bossier shales. Borrowing base on credit agreement will be reduced to $100MM following the closing of the sale

SLIDE 3

Shareholder Approval and NYSE Update Issue Requirements/Considerations 1 Recent Capital Transactions NYSE 1% Rule: Requires consent of shareholders if a related party (director, officer and holder of more than 5% of outstanding shares) is issued in excess of 1% of the total outstanding number of shares NYSE 20% Rule: Requires consent of shareholders if the total equity issued exceeds 20% of the outstanding common stock Transaction was structured to allow deal to close and fund before achieving shareholder approval Defer PIK into equity until shareholder approval is received, but the Company does have the ability to PIK with debt Company is recommending shareholders approve the issuance of shares for PIK feature of transaction Annual meeting set for May 31, ‘17 2 Reverse Share Split Company received a notice of non-compliance from NYSE in January 2017 because average closing share price was less than $1.00 for a consecutive 30 trading-day period Company is seeking shareholder approval to give Board of Directors authority for a reverse share split in a range of 1-for-10 to 1-for-20 Reverse share split will cure share price compliance issue and allow Company to continue to be listed on NYSE As part of the reverse share split, the Company will seek less than a proportionate reduction of its authorized common shares. The proposal will permit a 1/5th reduction in proportion to the reverse share split ratio. The additional authorized common shares will allow the Company to use the PIK into common shares provisions of the 1.5 Lien Notes and 1.75 Lien Term Loans. Requires 2/3rds approval of outstanding shares for the reverse share split

SLIDE 4

Operating Area Overview 1 Core Basins 2 Net Production 16-17; Mmcfe/d 3 EXCO Overview: Three Concentrated Resource Positions As of December 31, ’16 Currently operating 4 rigs Proved reserves were based on December 30, 2016 NYMEX futures prices, in each case adjusted for geographical and historical differentials. The NYMEX proved reserves disclosed differ from proved reserves that would be prepared based on the methodology prescribed by GAAP primarily due to the oil and natural gas prices and the development plans utilized in the classification of undeveloped locations. This measure should not be purported to be in accordance with GAAP nor is it indicative of the Company’s proved reserves if they were prepared in accordance with GAAP Appalachia South Texas East Texas / North Louisiana East Texas and North Louisiana Net Acres/%HBP1 96,300/87% Q1 ‘17 Operated Rigs2 1-3 Q1 ‘17 Net Production (Mmcfe/d) 187 12/31/16 Proved Reserves (Bcfe)3 1,110 South Texas Net Acres/% HBP1 49,300/95% Q1 ‘17 Operated Rigs 0 Q1 ‘17 Net Production (Boe/d) 4,000 12/31/16 Proved Reserves (Bcfe)3 155 Appalachia and Other Net Acres/% HBP1 184,100/93% Q1 ‘17 Operated Rigs 0 Q1 ‘17 Net Production (Mmcfe/d) 30 12/31/16 Proved Reserves (Bcfe)3 238 Total Net Acres/% HBP1 329,700/92% Q1 ‘17 Operated Rigs2 1-3 Q1 ‘17 Net Production (Mmcfe/d) 241 12/31/16 Proved Reserves (Bcfe)3 1,503

SLIDE 5

Capital Program Overview 17; Mixed Measures 1 Capital Budget By Type 17; $MM 2 Drilling and Completion3 17; # 3 Category Descriptions Drilling Currently running 4 rigs; plan to hold 4 rig program through 2017 Drilling focused in NLA Haynesville for highest economic returns NLA Bossier appraisal test with long lateral and enhanced completion design recently TTS; plan to drill four additional Bossier appraisal wells in 2017 to unlock upside Completion 1-2 frac fleets 3,500 lb/ft completion design with higher fracture intensity on new wells 50% of the program consists of 7,500 ft laterals or longer Program includes 4,500, 7,500 and 10,000 ft laterals Non-Operated Activity Haynesville Non-op activity is moving higher (5x 2016 level) Higher proppant tests, longer laterals and spacing tests will be considerations in well elections East TX appraisal will continue in 2017 through participation in certain wells in the Shelby area Land Land investment supports the 2017 drilling plans Area Gross Spuds Net Spuds Gross Completions Net Completions North LA 38 15.9 26 11.1 Appalachia 0 0.0 1 0.5 Total 38 15.9 27 11.6 Category Drilling and Completion1 137 Field Operations 4 Land 7 Corporate & Other2 10 Total 158 2017 program with 4 rigs focused on North LA to deliver highest returns in portfolio; spud 38 gross (15.9 net) EXCO operated wells 2017 Capital Budget Includes $122 million of operated and $15 million of non-operated drilling and completion costs Includes $5 million of capitalized interest and $4 million of capitalized general and administrative expenses EXCO operated

SLIDE 6

NLA Cumulative Gas vs. Time Mcf; Days 1 ETX Cumulative Gas vs. Time Mcf; Days 2 Well Performance 3 NLA Caddo 7,500’ Type Curve Progression 2016+; Bcf/1000’ 4 Improve Drilling and Completion Performance to Improve Capital Returns Wells with ~2,700 lb/ft completions performance exceeding expectations Larger stimulation design having positive impact on existing wells Larger completions and longer laterals delivering 149% more volume in approximately 275 days on line in NLA Three long lateral wells in NLA turned-to-sales in Q3 ‘16 averaged $8.8MM/well Larger completions delivering 45% more volume in approximately 600 days online in ETX Most recent well TTS in the southern area of ETX in Q1 ‘16 cost $10.3MM. This well was drilled in the deepest part of the Haynesville play to a TVD of >14,500’ NLA and ETX wells continue to exceed expectations; pressure decline is currently <10 psi/day and volumes continue to exceed type curve expectations NPV-10 (8/8ths) of Target is $8.9MM, up from $6.9MM at YE ‘15 60% 89% 45%

SLIDE 7

Drilling Inventory1 Breakeven Price Required for 25% IRR ($/Mcf)2; Gross/Net Locations 1 High Quality Drilling Inventory EXCO has more than 19 years of economic drilling locations with a 4 rig program drilling 41 wells per year Excludes South Texas locations Breakeven figures are wellhead returns

SLIDE 8

Financial and Operational Results Percentage change calculated using net wells drilled and net wells turned to sales Adjusted General and Administrative is a non-GAAP measure. See appendix for definition and reconciliation Cash interest expenses exclude interest paid or accrued in-kind, the amortization of debt issuance costs, discount on notes and capitalized interest. In addition, cash payments under the second lien term loan ("Exchange Term Loan") and a portion of the 1.75 Lien Term Loans are not considered interest expense per FASB ASC 470-60, Troubled Debt Restructuring by Debtors ("ASC 470-60") and are excluded from the cash interest expenses amounts shown Adjusted EBITDA is a non-GAAP measure. See appendix for definition and reconciliation Factors Unit Quarter-to-Date Year-to-Date 1Q 17 4Q 16 1Q 16 1Q 17 1Q 16 Actual Actual % Change Actual % Change Actual Actual % Change Rig Count # 1 0 100 2 (50) 1 2 (50) Gross/Net Wells Drilled # 4/3.5 0/0.0 1001 5/4.3 (19)1 4/3.5 5/4.3 (19)1 Gross/Net Wells Turned to Sales # 0/0.0 1/0.4 (100)1 8/3.6 (100)1 0/0.0 8/3.6 (100)1 Production Oil Mbbl 331 381 (13) 550 (40) 331 550 (40) Natural Gas Bcf 19.7 21.9 (10) 23.5 (16) 19.7 23.5 (16) Total Bcfe 21.7 24.2 (10) 26.8 (19) 21.7 26.8 (19) Total Daily Mmcfe/d 241 263 (8) 295 (18) 241 295 (18) Realized Price Differentials Oil $/Bbl (2.91) (2.86) 2 (5.23) (44) (2.91) (5.23) (44) Natural Gas $/Mcf (0.63) (0.50) 26 (0.55) 15 (0.63) (0.55) 15 Financial Results Lease Operating Expense $/Mcfe 0.39 0.36 8 0.35 11 0.39 0.35 11 Production Taxes $/Mcfe 0.16 0.09 78 0.17 (6) 0.16 0.17 (6) Gathering and Transportation $/Mcfe 1.26 1.10 15 0.94 34 1.26 0.94 34 Adj. General and Administrative2 $MM 6 6 2 9 (30) 6 9 (30) Interest Expense3 $MM 15 16 (6) 17 (12) 15 17 (12) Adj. EBITDA4 $MM 18 26 (31) 21 (14) 18 21 (14) Capital Expenditures $MM 18 8 125 37 (51) 18 37 (51)

SLIDE 9

Actuals to Guidance Comparison Excludes equity based compensation Interest expenses exclude interest paid or accrued in-kind, the amortization of debt issuance costs, discount on notes and capitalized interest. In addition, cash payments under the second lien term loan ("Exchange Term Loan") and a portion of the 1.75 Lien Term Loans are not considered interest expense per FASB ASC 470-60, Troubled Debt Restructuring by Debtors ("ASC 470-60") and are excluded from the cash interest expenses amounts shown Pro forma for STX divestiture Factors Unit Three Months Ended 1Q 17 1Q 17 Guidance 2Q 17 Guidance3 Actual Low High Low High Wells Spud (Gross/Net) # 4/3.5 5/3.9 11/3.9 Wells Turned to Sales (Gross/Net) # 0/0.0 0/0.0 4/3.5 Production Oil Mbbl 331 300 320 200 220 Natural Gas Bcf 19.7 19.4 20.1 18.4 19.2 Total Bcfe 21.7 21.2 22.1 19.6 20.5 Total Daily Mmcfe/d 241 235 245 215 225 Realized Price Differentials Oil $/Bbl (2.91) (3.00) (4.00) (3.00) (4.00) Natural Gas $/Mcf (0.63) (0.50) (0.60) (0.50) (0.60) Financial Results Lease Operating Expense $/Mcfe 0.39 0.40 0.45 0.35 0.40 Production Taxes $/Mcfe 0.16 0.15 0.20 0.15 0.20 Gathering and Transportation $/Mcfe 1.26 1.20 1.25 1.25 1.30 General and Administrative1 $MM 6 9 10 6 7 Interest Expense2 $MM 15 24 28 12 16

SLIDE 10

Appendix

SLIDE 11

Hedge Positions Factors Unit Nine Months Ended 12/31/17 Twelve Months Ended 12/31/18 Volume Price Volume Price Natural Gas Fixed Price Swaps - Henry Hub Bbtu, $/Mmbtu 27,500 3.05 3,650 3.15 Collars - Henry Hub Bbtu 8,250 Sold Call Options $/Mmbtu 3.28 Purchased Put Options $/Mmbtu 2.87 Oil Fixed Price Swaps - WTI Mbbl, $/Bbl 137 50.00 - - Percent Hedged1 Natural Gas % 74 8 Oil % 16 - Percent hedged based on PDP production forecast

SLIDE 12

Single Well Economics – Internal Type Curves Economics based on NYMEX futures prices as of March 31, 2017, including natural gas prices per MMBtu of $3.31 for 2017, $3.04 for 2018, $2.83 for 2019, $2.82 for 2020, $2.83 for 2021, $2.84 for 2022, $2.88 for 2023, $2.94 for 2024 and $3.00 thereafter     Unit NLA DeSoto Core NLA Caddo X-Unit Lateral NLA Caddo Standard Lateral NLA Bossier X-Unit Lateral ETX Shelby HSVL ETX Highlander HSVL ETX Highlander BSSR 1 Target Lateral Length Ft 4,500 7,500 4,500 7,500 7,500 6,500 6,500 2 Gross Locations # 20 46 23 168 63 57 65 3 Net Locations # 9 12 9 78 25 13 17 4 WI % 43 25 37 46 39 23 26 5 NRI % 33 19 28 36 31 18 20 6 Spacing Acres 136 227 136 227 241 221 223   Type Curve                 7 IP Mcf/d 14,000 17,600 13,200 10,900 9,300 11,500 9,500 8 Phase I – Duration Month Month 16 16 16 12 12 18 16 9 Phase I – B Factor x 0 0 0 0 0 0 0 10 Phase I – Initial Decline % 50 40 52 41 22 22 22 11 Phase II – Duration Month Month 10 10 10 14 15 54 56 12 Phase II – B Factor x 0.6 0.6 0.6 0.6 0.6 0.6 0.6 13 Phase II – Initial Decline % 51 52 51 37 42 42 41 14 Phase III – Duration Month Month 16 16 16 16 9 24 24 15 Phase III – B Factor x 1 1 1 1 1 1 1 16 Phase III – Initial Decline % 42 42 42 37 39 25 25 17 Phase IV – Initial Decline % 32 32 32 26 36 22 22 18 Terminal Decline % 6 6 6 6 6 6 6 19 Wellhead EUR Bcf 9.9 14.9 8.9 12 11.3 14.1 11.7 20 EUR per 1,000’ (lateral length) Bcf 2.2 1.98 1.98 1.6 1.5 2.2 1.8 21 D&C $MM 6.9 9.5 6.9 11.4 9.5 10.0 9.6 22 LOE Fixed $/month 1,770 1,770 1,770 1,770 3,034 2,690 2,690 23 Variable/Gathering Expense $/mcf .05/.47 .05/.47 .05/.47 .06/.47 0.08/0.29 0.06/0.31 0.06/0.31   Single Well Returns                 24 Breakeven Flat Price (25%) $/MMBTU 2.36 2.26 2.53 3.28 2.86 2.46 2.78 25 PV/I, Disc1 x 1.82 1.95 1.64 1.19 1.40 1.72 1.46

SLIDE 13

    Three Months Ended (in thousands)   March 31, 2017 December 31, 2016 March 31, 2016 Net income (loss)   $ 8,193   $ (34,699) $ (130,148 ) Interest expense   19,952   16,252 19,257   Income tax expense   1,028   1,027 —   Depletion, depreciation and amortization   11,508   11,987 29,001   EBITDA (1)   $ 40,681   $ (5,433 ) $ (81,890 ) Accretion of discount on asset retirement obligations   212   204 912   Impairment of oil and natural gas properties   —   — 134,599   Other items impacting comparability   —   — 402   (Gain) loss on restructuring and extinguishment of debt   6,272   (83) (45,114 ) Equity (income) loss   (317 ) 7,608 7,910   Gain (loss) on derivative financial instruments - commodity derivatives   (15,533 ) 22,505 (16,591 ) Cash receipts (payments) of commodity derivative financial instruments   (4,459 ) 1,052 16,790   Gain on derivative financial instruments - common share warrants   (6,004 ) — —   Equity-based compensation   (2,382 ) 220 3,813   Adjusted EBITDA (1)   $ 18,470   $ 26,073 $ 20,831   Interest expense   (19,952 ) (16,252) (19,257 ) Current income tax expense   —   — —   Amortization of deferred financing costs and discount   4,402   2,006 3,121   Other operating items impacting comparability and non-operating items   (21 ) 5 (422 ) Changes in working capital   2,297   (8,506) 23,708   Net cash provided by operating activities   $ 5,196   $ 3,326 $ 27,981                       Consolidated EBITDA and Adjusted EBITDA Reconciliations Non-GAAP Measures and Reconciliations Earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”) represents net income (loss) adjusted to exclude interest expense, income taxes and depreciation, depletion and amortization. “Adjusted EBITDA” represents EBITDA adjusted to exclude accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives, non-cash impairments of assets, equity-based compensation, income or losses from equity method investments and other operating items impacting comparability. EXCO has presented EBITDA and Adjusted EBITDA because they are a widely used measure by investors, analysts and rating agencies for valuations, peer comparisons and investment recommendations. In addition, similar measures are used in covenant calculations required under the Credit Agreement, the indenture governing the 1.5 Lien Notes, the indenture governing the 2018 Notes, the indenture governing the 2022 Notes and the term loan credit agreement governing the 1.75 Lien Term Loans. Compliance with the liquidity and debt incurrence covenants included in these agreements is considered material to the Company. EXCO's computations of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies due to differences in the inclusion or exclusion of items in the Company's computations as compared to those of others. EBITDA and Adjusted EBITDA are measures that are not prescribed by GAAP. EBITDA and Adjusted EBITDA specifically exclude changes in working capital, capital expenditures and other items that are set forth on a cash flow statement presentation of the Company’s operating, investing and financing activities. As such, investors are encouraged not to use these measures as substitutes for the determination of net income, net cash provided by operating activities or other similar GAAP measures. The calculation of EBITDA and Adjusted EBITDA as presented herein differ in certain respects from the calculation of comparable measures in the Credit Agreement, the indentures and the term loan credit agreements.     Three Months Ended (in thousands)   March 31, 2017   December 31, 2016   March 31, 2016 General and administrative, GAAP   $ 4,415     $ 10,074     $ 10,897   Less: Equity-based compensation   2,382     (220 )   (3,813 ) Less: Restructuring and severance costs   (775 )   (3,936 )   1,489   Adjusted general and administrative, non-GAAP measure (1)   6,022     5,918     8,573                               The Company believes this non-GAAP measure is used by investors, analysts and management for valuations, peer comparisons and other recommendations. The exclusion of equity-based compensation is important to users that are evaluating the impact of the Company's cash-based general and administrative costs on its credit metrics and ability to service its indebtedness. In addition, the exclusion of cash-based costs, such as restructuring and severance, assists in the comparability between periods and similar measures are used in debt covenant calculations required under certain of the Company's debt agreements. Restructuring costs include legal and advisory costs incurred in connection with the Company's strategic initiatives focused on restructuring its balance sheet and gathering and transportation contracts, and severance costs relate primarily to the Company's reductions in workforce. Adjusted General and Administrative Expenses Reconciliations

SLIDE 14

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 limitations on our ability to incur certain types of indebtedness under our debt agreements and to refinance or replace existing debt obligations as they mature; 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; outcome of divestitures of non-core assets, including the potential sale of our assets in the South Texas region; cash flow and liquidity; our ability to enter into transactions as a result of our credit rating, including commodity derivatives with financial institutions and services with vendors; timing and amount of future production of oil and natural gas; availability of drilling and production equipment; availability of water, sand 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 commodity derivative financial instruments; decisions whether or not to enter into commodity 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; our ability to execute our business strategies and other corporate actions; outcome of shareholder approvals related to the warrants and issuance of common shares in connection with the 1.5 Lien Notes and 1.75 Lien Term Loans; decisions to pay interest on the 1.5 Lien Notes and 1.75 Lien Term Loans in cash, common shares or additional indebtedness; and our ability to continue as a going concern 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 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, 2016, filed with the Securities and Exchange Commission ("SEC") on March 16, 2017 and its other periodic filings with the SEC. 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. Revenues, operating results and financial condition substantially depend on prevailing prices for oil and natural gas and the availability of capital from our credit agreement. 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. EXCO undertakes no obligation to publicly update or revise any forward-looking statements.