First Quarter 2016 Review Hal Hickey Harold Jameson Ricky Burnett Chief Executive Officer Chief Operating Officer Chief Financial Officer May 4, 2016
Strategic Plan Update 2 Focus Area # Improvement Plan 16 Update Liability Management 1 2 Improve Debt Structure To Provide Structural Liquidity Restructure Gathering And Transportation Contracts To Provide Liquidity Borrowing base redetermined at $325MM in connection with semi-annual process; $256MM of liquidity as of March 31, 2016 Repurchased $54MM of unsecured notes with cash for $8MM Continuing to evaluate financing alternatives including the repurchase, refinancing or exchange of existing indebtedness, issuance of additional indebtedness or issuance of equity Remain committed to working with midstream and transportation providers to restructure gathering and transportation contracts Significant amount of underutilized capacity with fee structures above current market rates 3 Reduce G&A Load To Reduce Fixed Cost Burden Reduced G&A headcount by an additional 20% since Decreased G&A and LOE costs by 27% and 25% compared to Expect G&A and LOE costs to continue to decrease during 16 Continue to rationalize corporate costs Operational Performance 4 Capital Deployment 5 Improve Drilling And Completion Performance To Improve Capital Returns Implement A Liquidity Driven Prioritized Capital Allocation System To Ensure Highest And Best Use Of Capital Completion program utilized up to 2,800 lbs of proppant per lateral foot during 16 Drilled NLA Haynesville well in 23 days (spud to rig release) during 16, a new Company record Average cost for the ETX Haynesville wells turned to sales during 16 was $8.9MM, $1.2MM below budget; NLA Haynesville wells expected to cost $6.0MM, $0.7MM below budget Reduced 16 capital program to $85MM versus capital expenditures of $277MM Measure capital allocation decisions against liquidity intensity benchmark Elected to defer additional development to preserve capital resources Evaluating divestiture of non-core assets
#1: Improve Debt Structure To Provide Structural Liquidity Debt And Liquidity Dec Mar 16; Mixed Measures 1 16 Update 2 $MM Unless Otherwise Noted Mar 16 Dec Delta % Cash And Restricted Cash 1 74 33 124 Credit Agreement 3 67 99 2nd Lien Term Loans 2 700 700 0 18 Senior Notes 4 8 (9) 22 Senior Notes 183 223 (18) Gross Debt 2 1,9 1,8 1 Net Debt 2 1,086 1,1 (3) Borrowing Base 325 375 () Liquidity 256 334 (23) Interest Coverage Ratio ( 1.25x) 2.2x 2.4x (8) 1 st Lien Leverage Ratio ( 2.5x) 0.7x 0.3x 3 Focused on improving capital structure and providing structural liquidity Completed semi-annual redetermination resulting in a borrowing base of $325MM, a % decline from the previous $375MM borrowing base Utilized $8MM of cash to repurchase $MM and $40MM in principal of 18 and 22 senior unsecured notes, respectively, resulting in a yearly interest expense reduction of $4MM Since, the Company has reduced its senior unsecured notes by $924MM, or 74% The Company continues to evaluate additional capital structure initiatives, including the repurchase, refinancing or restructuring of existing indebtedness, issuance of additional indebtedness or issuance of equity 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 $28 million and $21 million as of Mar. 31, 16 and Dec. 31,. 2. Represents total principal balance outstanding. The issuance of the Exchange Term Loan and related repurchases of 18 Notes and 22 Notes were accounted for in accordance with ASC 470-60. As a result, the carrying amount of the Exchange Term Loan is equal to the total undiscounted future cash payments, including interest and principal. 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 the next twelve months 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
#2 Restructure Gathering And Transportation Contracts To Enhance Liquidity 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. 4 ETX/NLA Gross Transportation Commitments 16; $MM 1 Execution Strategy 2 The Company remains committed to working with its midstream and transportation providers to restructure contracts, which include contracts with a significant amount of underutilized 31 capacity and fee structures above the current market rates More must be done to restructure contracts 53 126 Market unutilized portion of transportation to increase utilization Evaluate M&A transactions to increase utilization 42 Total '16 Market Value Above Market Value Unused At Market Value Total '16 Contracted Value 1 2 3 4 Continue to blend and extend gathering and transportation contracts Evaluate options to issue secured debt in exchange for cost relief Consider other commercial options
#3: Reduce LOE And G&A Load To Reduce Fixed Cost Burden 1. Represents GAAP G&A of $.2MM adjusted to exclude $1.7MM of non-cash equity based compensation, annualized. 2. Represents 16 GAAP G&A of $10.9MM adjusted to exclude $3.8MM of non-cash equity based compensation, annualized. 5 LOE By Quarter -16; $MM 1 40% LOE Reduction Since Headcount Reduction -16; Mixed Measures 2 52% Headcount Reduction Since $54MM 1 G&A Run Rate 558 12 9 $28MM 2 G&A Run Rate 270 16 ' Current
#4: Improve Drilling And Completion Performance To Improve Capital Returns 6 ETX Drilling Days Versus Depth ; ft, Days 1 NLA Drilling Days Versus Depth 16; ft, Days 2 0 5,000 Budget 46 Days AVG 39 Days 0 5,000 Budget 31 Days AVG 25 Days 10,000,000 20,000 10,000,000 0 10 20 30 40 50 0 10 20 30 40 Well A Well B Well C Well D Well E Well F AFE Well AFE Well Well A Well B Well C ETX/NLA Well Cost Reduction -16; % 3 Completion & Rentals -56% Drilling Rig & Mobilization Drilling Rentals Tubulars Fuel, Mud & Chemicals Directional Services -31% -27% -24% -21% -21% Well Construction Currently drilling fastest wells in company history ETX wells with total depth greater than 20,100 feet measured depth are seven days under budget NLA wells are six days under budget Record low well costs derived from improved performance, design changes, efficiencies and service cost reductions ETX $8.9MM (down $1.2MM) (HSVL, varying lateral lengths) NLA $6.0MM (down $0.7MM) Lowest cost in company history 4 ETX Haynesville wells completed in 16 drilled in record time and average $1.2MM below budget; NLA wells drilled in record time and expected cost $0.7MM below budget
#5: Implement A Liquidity Driven Prioritized Capital Allocation System To Ensure Highest And Best Use of Capital Capital Program Overview 16; Mixed Measures 1 Category Reduced 16 Program 16 Development Activity Descriptions Announced additional reduction in 16 capital program on March 30 Elected to defer additional development to preserve capital resources and give time to work with midstream 16 capital budget of $85 million, represents a reduction of $192 million, or 69%, compared to capital expenditures of $277 million Currently plan to drill 7 gross wells and complete gross wells in 16, with development activities focused on natural gas drilling and completion activities in the Haynesville and Bossier shales in NLA and ETX No 16 development activity planned in STX or Appalachia Capital Budget By Type 16; $MM 2 Category Drilling and Completion 66 Field Operations and Non-Operated 5 Land 4 Capitalized Costs 10 Total 85 Development Capital Spending By Area 16; # 3 Area Gross Spuds Net Spuds Gross Completions Net Completions ETX 1 0.3 9 3.9 NLA 6 5.5 6 5.5 Total 7 5.8 9.4 EXCO is focused on preserving its capital resources for future growth and, based on current natural gas prices and time to work with midstream providers, the Company has decided to significantly reduce its drilling activity in 16 7
No Near Term Debt Maturities Debt Principal And Liquidity -16; Mixed Measures 1 1Q 16 4Q Debt Principal Maturity Profile 16-22; $MM 2 Factors Unit Actual Actual % Debt Schedule Cash And Restricted Cash 1 $MM 74 33 124 Credit Agreement $MM 3 67 99 2 nd Lien Term Loans 2 $MM 700 700 0 18 Senior Notes $MM 4 8 (9) 22 Senior Notes $MM 183 223 (18) Total Debt 2 $MM 1,9 1,8 1 Net Debt 2 $MM 1,086 1,1 (3) Liquidity North Borrowing Louisiana Base Drilling Cost Per $MM Foot 325 375 () 10-E; Credit Agreement $/ft $MM 3 67 399 Letters Of Credit $MM 10 7 43 Available For Borrowing $MM 182 301 (40) Cash And Restricted Cash 1 $MM 74 33 124 Liquidity $MM 256 334 (23) Key Metrics Adjusted EBITDA 3 /Interest 4 ( 1.25x) x 2.2 2.4 (8) Sr. Secured Debt 2 /LTM Adjusted EBITDA 3,4 ( 2.5x) x 0.7 0.3 3 Net Debt 2 /LTM Adjusted EBITDA 3 X 5.5 4.7 17 3 700 4 183 16 17 18 19 20 21 22 Unsecured Notes Second Lien Credit Agreement Liquidity And Capital -16; Mixed Measures 3 Factors Unit 1Q 16 4Q Actual Actual Liquidity $MM 256 334 Capital Budget $MM 85 103 Capital Budget/Liquidity % 33 31 Forward 12 Commodity Price $/Mmbtu 2.44 2.11 1. Includes restricted cash of $28 million and $21 million as of Mar. 31, 16 and Dec. 31,. 2. Represents total principal balance outstanding. The issuance of the Exchange Term Loan and related repurchases of 18 Notes and 22 Notes were accounted for in accordance with ASC 470-60. As a result, the carrying amount of the Exchange Term Loan is equal to the total undiscounted future cash payments, including interest and principal. 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 the next twelve months 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 Mar. 31, 16 and Dec. 31,, the ratio of consolidated EBITDAX to consolidated interest expense (as defined in the agreement including interest expense calculated in accordance with GAAP) was 2.2 to 1.0 and 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 0.7 to 1.0 and 0.3 to 1.0, respectively. 8
Financial And Operational Results Quarter-to-Date Year-to-Date 1Q 16 4Q 1Q 1Q 16 1Q Factors Unit Actual Actual % Change Actual % Change Actual Actual % Change Rig Count # 2 3 (33) 4 (50) 2 4 (50) Net Wells Drilled # 4.6 2.7 70 5.5 (16) 4.6 5.5 (16) Net Wells Turned To Sales # 3.6 4.3 (16).6 (75) 3.6.6 (75) Production Oil Mbbl 550 609 (10) 504 9 550 504 9 Natural Gas Bcf 23.5 25.7 (9) 27.5 () 23.5 27.5 () Total Bcfe 26.8 29.3 (9) 30.5 (12) 26.8 30.5 (12) Total Daily Mmcfe/d 295 319 (8) 339 () 295 339 () Realized Price Differentials Oil $/Bbl (5.23) (4.57) (6.96) (25) (5.23) (6.96) (25) Natural Gas $/Mcf (0.55) (0.65) () (0.60) (8) (0.55) (0.60) (8) Financial Results Lease Operating Expense $/Mcfe 0.35 0.41 () 0.49 (29) 0.35 0.49 (29) Production Taxes $/Mcfe 0.17 0.21 (19) 0.16 6 0.17 0.16 6 Gathering And Transportation $/Mcfe 0.99 0.86 0.84 18 0.99 0.84 18 General And Administrative 1 $MM 7 (50) (50) 7 (50) Cash Interest Expense 2 $MM 17 21 (19) 26 (35) 17 26 (35) Adjusted EBITDA 3 $MM 19 50 (62) 58 (67) 19 58 (67) Capital Expenditures $MM 37 35 6 103 (64) 37 103 (64) 1. Excludes equity-based compensation expenses of $3.8 million, $3.2 million and $1.7 million for the three months ended Mar. 31, 16, Dec. 31, and Mar. 31,, 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 16 total $50.0 million. 3. Adjusted EBITDA is a non-gaap measure. See appendix for definition and reconciliation. 9
Actuals To Guidance Comparison Three Months Ended 1Q 16 1Q 16 Guidance 2Q 16 Guidance Full Year 2016 Guidance Factors Unit Actual Low High Low High Low High Rig Count (Gross) # 2 2 1 0.75 Wells Drilled (Gross/Net) # 5/4.6 5/4.3 1/0.9 7/5.8 Wells Turned To Sales (Gross/Net) # 8/3.6 8/3.6 6/5.6 /9.4 Production Oil Mbbl 550 525 535 470 490 1,840 1,860 Natural Gas Bcf 23.5 23.2 24.1 24.5 25.3 95.1 102.3 Total Bcfe 26.8 26.4 27.3 27.3 28.2 106.1 1.5 Total Daily Mmcfe/d 295 290 300 300 310 290 310 Realized Price Differentials Oil $/Bbl (5.23) (4.00) (6.00) (4.00) (6.00) (4.00) (6.00) Natural Gas $/Mcf (0.55) (0.60) (0.70) (0.60) (0.70) (0.60) (0.70) Financial Results Lease Operating Expense $/Mcfe 0.35 0.40 0.45 0.35 0.40 0.35 0.40 Production Taxes $/Mcfe 0.17 0. 0.20 0. 0.20 0. 0.20 Gathering And Transportation $/Mcfe 0.99 0.90 0.95 0.95 1.00 0.95 1.00 General And Administrative 1 $MM 7 7 8 6 7 25 27 Cash Interest Expense 2 $MM 17 17 19 17 19 65 70 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 16 are $50.0 million. 10
Hedge Positions Nine Months Ended 12/31/16 Twelve Months Ended 12/31/17 Twelve Months Ended 12/31/18 Factors Unit Volume Price Volume Price Volume Price Natural Gas Fixed Price Swaps - Henry Hub Fixed Price Swaptions Henry Hub 2 Bbtu, $/Mmbtu 42,625 2.88 20,050 3.00 3,650 3. Bbtu, $/Mmbtu - - 7,300 2.76 - - Oil Fixed Price Swaps - WTI Mbbl, $/Bbl 825 58.61 - - - - Percent Hedged 1 Natural Gas % 77 50 9 Oil % 68 - - 1. Percent hedged based upon PDP production forecast and includes swaption volumes. 2. Exercisable on Dec. 22, 16. 11
Appendix
EXCO Overview: Three Concentrated Resource Positions 1. As of Dec. 31,. 2. The Total Proved Reserves as of Dec. 31, 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. Net production excludes production from divested assets. Operating Area Overview 1 Core Basins 2 East Texas And North Louisiana Net Acres/%HBP 1 97,600/96% 16 Operated Rigs 2 16 Net Production (Mmcfe/d) 2 Year End Proved Reserves (Bcfe) 2 726 South Texas Net Acres/% HBP 1 65,800/81% 16 Operated Rigs 0 16 Net Production (Boe/d) 6,500 Year End Proved Reserves (Bcfe) 2 129 Appalachia And Other Net Acres/% HBP 1 272,800/87% 16 Operated Rigs 0 16 Net Production (Mmcfe/d) 42 Year End Proved Reserves (Bcfe) 2 52 Total Net Acres/% HBP 1 436,200/88% 16 Operated Rigs 2 16 Net Production (Mmcfe/d) 295 Year End Proved Reserves (Bcfe) 2 907 Net Production 3-16; Mmcfe/d 3 394 392 441 420 380 358 333 331 339 361 340 319 295 South Texas East Texas / North Louisiana Appalachia 16
East Texas Overview 1. As of Dec. 31,. Operating Area Overview 1 Area Of Operations 2 Attribute Key Features Total Acreage 1 46,100 net acres (45,800 shale) 88% HBP Active Wells 104 wells flowing to sales Production 16: 63 Mmcfe/d Targeted Formations Haynesville Bossier 16 Results Produced 63 Mmcfe/d, a decrease of 1 Mmcfe/d, or 2%, from Turned-to-sales 8 gross (3.6 net) operated Haynesville and Bossier wells in 16 Completed wells utilizing 2,100 to 2,800 lbs of proppant per lateral foot Average cost for the Haynesville wells was $8.9MM, $1.2MM below budget Completed second Nacogdoches County well with initial production rate of.2 Mmcfe/d on a 17/64 th restricted choke; opportunity to unlock over 100 undeveloped locations in the area Net Production -16; Mmcfe/d 3 43 37 30 25 22 22 25 47 45 40 52 64 63 16
Improve Economics Through Disciplined Execution And Cost Reductions 8,0 00 7,0 00 6,0 00 5,0 00 4,0 00 3,0 00 2,0 00 1,0 00 0 1. Based on Haynesville well cost. 70 60 50 40 30 20 10 0 ETX Lateral Length And Days To Drill 10-16; ft; Days 1 1 59 54 52 47 Days to drill 43 38 ETX D&C Cost Per Lateral Foot 10-16; $/ft 1 2 4,717 4,675 5,090 6,520 6,841 6,889 3,011 2,870 2,193 1,910 1,461 1,293 10 11 12 '16 10 11 12 '16 ETX Drilling Cost Per Foot 10-16; $/ft 1 3 ETX Proppant Per Lateral Foot 10-16; lbs/ft 1 4 348 360 316 270 236 201 800 850 950 1,400 2,530 2,600 10 11 12 '16 10 11 12 '16
North Louisiana Overview 1. As of Dec. 31,. 16 Operating Area Overview 1 Area Of Operations 2 Attribute Key Features Total Acreage 1 51,500 net acres (38,000 shale) 100% HBP Active Wells 4 wells flowing to sales Production 16: 1 Mmcfe/d Targeted Formations Haynesville Bossier 16 Results Produced 1 Mmcfe/d, a decrease of 23 Mmcfe/d, or %, from Drilled 5 gross (4.6 net) operated Haynesville wells in 16 Net Production -16; Mmcfe/d 3 329 Completing wells utilizing 2,700 lbs of proppant per lateral foot Average cost for the Haynesville wells expected to be $6.0MM, $0.7MM below budget, with average lateral lengths of 4,300 feet 291 310 286 259 235 217 193 207 231 197 174 1 Implemented several initiatives to enhance and manage base production and reduce gathering system pressure 16
Improve Economics Through Disciplined Execution And Cost Reductions 4,4 00 4,3 00 4,2 00 4,1 00 4,0 00 3,9 00 3,8 00 50 45 40 35 30 25 20 10 5 0 17 NLA Lateral Length And Days To Drill 10-16; ft, Days 1 47 4,019 41 37 4,219 4,2 35 4,258 37 4,346 Days to drill 32 25 4,264 4,250 NLA D&C Cost Per Lateral Foot 10-16; $/ft 2 2,742 2,375 1,971 1,643 1,765 1,664 1,351 10 11 12 '16 NLA Drilling Cost Per Foot 10-16; $/ft 3 10 11 12 '16 NLA Proppant Per Lateral Foot 10-16; lbs/ft 4 294 289 278 254 255 234 172 1,600 1,650 1,200 900 750 800 2,700 10 11 12 '16 10 11 12 '16
South Texas Overview 1. As of Dec. 31,. 18 Operating Area Overview 1 Area Of Operations 2 Attribute Key Features Total Acreage 1 65,800 net acres 81% HBP (100% Core) Active Wells 235 wells Production 16: 6.5 MBoe/d Targeted Formations Eagle Ford Buda 16 Results Produced 6.5 Mboe/d, a decrease of 0.8 Mboe/d, or 11%, from No development activity during 16 Acreage position is largely held-byproduction, providing flexibility in timing of development Net Production -16; Boe/d 3 6,200 7,100 6,500 6,500 5,900 6,100 6,000 7,200 7,300 7,300 6,500 16
Appalachia Overview 1. As of Dec. 31,. 19 Operating Area Overview 1 Area Of Operations 2 Attribute Key Features Total Acreage 1 269,800 net acres (7,400 shale) 84% HBP (shale) Active Wells 126 Marcellus flowing to sales 5,509 conventional flowing to sales Production 16: 42 Mmcfe/d Targeted Formations Marcellus Utica and Upper Devonian 16 Results Produced 42 Mmcfe/d, an increase of 5 Mmcfe/d, or % from Elected to shut-in 8 Mmcfe/d during 16 due to low commodity prices Reduction in force during reduced headcount by 41% in the region to better align operations personnel and reduce costs Net Production -16; Mmcfe/d 3 56 64 64 66 61 62 56 55 51 47 47 37 42 Decreased lease operating expenses by 43% compared to and have reduced work hours by 20% compared to 16 16
Single Well Economics 16 Capital Program Internal Type Curves 1. Based on Mar. 31, 16 strip prices. See appendix for price details. 20 Unit ETX Shelby HSVL ETX Shelby Bossier NLA DeSoto Core 1 Target Lateral Length Ft 7,500 7,500 4,500 2 Gross Locations # 71 97 33 3 Net Locations # 29 41 16 4 WI % 41 42 47 5 NRI % 32 32 36 6 Spacing Acres 207 207 6 Type Curve 7 IP Mcf/d 9,400 9,400 16,000 8 Phase I Duration Month Month 16 9 Phase I B Factor x 0.6 0.6 0.0 10 Phase I Initial Decline % 22 22 60 11 Phase II Duration Month Month 7 7 n/a 12 Phase II B Factor x 0.6 0.6 1.0 Phase II Initial Decline % 42 42 57.1 Phase III Initial Decline % 33 33 n/a Terminal Decline % 6 6 6 16 Wellhead EUR Bcf/Mbo.0.0 9.5 17 EUR per 1,000 (lateral length) Bcf or Mbo 1.75 1.75 2.1 18 D&C/Pumping Unit $MM 9.2 9.5 6.0 19 LOE Fixed - WI $/month 2,866 2,866 2,465 20 Variable/Gathering Expense - WI $/Mcf,$/Bbl 0.03/0.27 0.03/0.27 0.01/0.42 Single Well Returns 21 PV10 (8/8ths) 1 $MM 4.2 3.9 3.1 22 IRR 1 % 27 24 40 23 Breakeven Flat Price (25% IRR) $/Mcf 2.60 2.71 2.27
EBITDA, Adjusted EBITDA, Adjusted Operating Cash Flow and Free Cash Flow Reconciliations 21
Forward Looking Statements 22 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, 20, 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.