EXCO Resources Inc.
Annual Report 2017

Plain-text annual report

Morningstar® Document Research℠ FORM 10-KEXCO RESOURCES INC - XCOOQFiled: March 15, 2018 (period: December 31, 2017)Annual report with a comprehensive overview of the companyThe information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The userassumes all risks for any damages or losses arising from any use of this information, except to the extent such damages or losses cannot belimited or excluded by applicable law. Past financial performance is no guarantee of future results.UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-Kþ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2017ORo ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM __________TO __________ Commission file number: 001-32743EXCO RESOURCES, INC.(Exact name of Registrant as specified in its charter)Texas(State of incorporation) 74-1492779(I.R.S. Employer Identification No.) 12377 Merit Drive, Suite 1700, Dallas, Texas(Address of principal executive offices) 75251(Zip Code)Registrant’s telephone number, including area code: (214) 368-2084Securities registered pursuant to Section 12 (b) of the Act: NoneSecurities registered pursuant to Section 12 (g) of the Act: Common Shares, par value $0.001 per shareIndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þIndicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þIndicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No oIndicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and postedpursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and postsuch files). Yes þ No oIndicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’sknowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. oIndicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.Large accelerated filer o Accelerated filer oNon-accelerated filer o Smaller reporting company þEmerging growth company o If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financialaccounting standards provided pursuant to Section 13(a) of the Exchange Act. oIndicate by check whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þAs of March 8, 2018, the registrant had 21,630,464 outstanding common shares, par value $0.001 per share, which is its only class of common shares. As of the last business dayof the registrant's most recently completed second fiscal quarter, the aggregate market value of the registrant's common shares held by non-affiliates was approximately$29,307,000.______________________________DOCUMENTS INCORPORATED BY REFERENCEThe registrant intends to file an amendment on Form 10-K/A not later than 120 days after the close of the fiscal year ended December 31, 2017. Portions of such amendment will beincorporated by reference into Part III, Items 10-14 of this Annual Report on Form 10-K.Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO RESOURCES, INC.TABLE OF CONTENTSPART I. Item 1.Business2Item 1A.Risk Factors29Item 1B.Unresolved Staff Comments45Item 2.Properties45Item 3.Legal Proceedings45Item 4.Mine Safety Disclosures46 PART II. Item 5.Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities46Item 6.Selected Financial Data48Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations49Item 7A.Quantitative and Qualitative Disclosures About Market Risk74Item 8.Financial Statements and Supplementary Data76Item 9.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure132Item 9A.Controls and Procedures132Item 9B.Other Information133 PART III. Item 10.Directors, Executive Officers and Corporate Governance134Item 11.Executive Compensation134Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters134Item 13.Certain Relationships and Related Transactions, and Director Independence134Item 14.Principal Accountant Fees and Services134 Part IV. Item 15.Exhibits and Financial Statement Schedules1341Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO RESOURCES, INC.PART IItem 1. BusinessGeneralUnless the context requires otherwise, references in this Annual Report on Form 10-K to “EXCO,” “EXCO Resources,” “Company,” “we,” “our,” and“us” are to EXCO Resources, Inc. and its consolidated subsidiaries.We have provided definitions of terms commonly used in the oil and natural gas industry in the “Glossary of selected oil and natural gas terms”section of this Annual Report on Form 10-K.We are an independent oil and natural gas company engaged in the exploration, exploitation, acquisition, development and production of onshoreU.S. oil and natural gas properties with a focus on shale resource plays. Our principal operations are conducted in certain key U.S. oil and natural gas areasincluding Texas, Louisiana and the Appalachia region.Bankruptcy proceedings under Chapter 11On January 15, 2018, the Company and certain of its subsidiaries, including EXCO Services, Inc., EXCO Partners GP, LLC, EXCO GP Partners OLP,LP, EXCO Partners OLP GP, LLC, EXCO Operating Company, LP, EXCO Midcontinent MLP, LLC, EXCO Holding (PA), Inc., EXCO Production Company(PA), LLC, EXCO Resources (XA), LLC, EXCO Production Company (WV), LLC, EXCO Land Company, LLC, EXCO Holding MLP, Inc., Raider Marketing,LP, Raider Marketing GP, LLC (collectively, the “Filing Subsidiaries” and, together with the Company, the “Debtors”), filed voluntary petitions for reliefunder Chapter 11 of the United States Bankruptcy Code (“Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas(“Court”). The Chapter 11 cases are being jointly administered under the caption In Re EXCO Resources, Inc., Case No. 18-30155 (MI) ("Chapter 11 Cases").The Court granted all of the first day motions filed by the Debtors that were designed primarily to minimize the impact of the Chapter 11 proceedings on ouroperations, customers and employees. We will continue to operate our businesses as “debtors in possession” under the jurisdiction of the Court and inaccordance with the applicable provisions of the Bankruptcy Code and orders of the Court. We expect to continue our operations without interruption duringthe pendency of the Chapter 11 proceedings.For the duration of the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to risks anduncertainties associated with Chapter 11 proceedings described in "Item 1A. Risk Factors”. As a result of these risks and uncertainties, our assets, liabilities,shareholders' equity, officers and/or directors could be significantly different following the conclusion of the Chapter 11 Cases, and the description of ouroperations, properties and capital plans included in this annual report may not accurately reflect our operations, properties and capital plans following theChapter 11 Cases. See further discussion of the Chapter 11 Cases in "Note 17. Subsequent events" in the Notes to our Consolidated Financial Statements.Our business strategyOur primary strategy focuses on the exploitation and development of our shale resource plays and the pursuit of leasing and acquisition opportunities.Our liquidity and ability to maintain compliance with debt covenants have been negatively impacted by the prolonged depressed oil and natural gas priceenvironment, levels of indebtedness, and gathering, transportation and certain other commercial contracts. We define liquidity as cash and restricted cashplus the unused borrowing base under certain revolving credit agreements ("Liquidity").During 2017, we focused on restructuring our balance sheet to improve our Liquidity and financial condition. On March 15, 2017, we closed a seriesof transactions including the issuance of $300.0 million in aggregate principal amount of senior secured 1.5 lien notes due March 20, 2022 ("1.5 LienNotes"), the exchange of $682.8 million in aggregate principal amount of our senior secured second lien term loans due October 26, 2020 ("Second LienTerm Loans") for a like amount of senior secured 1.75 lien term loans due October 26, 2020 ("1.75 Lien Term Loans," and such exchange, the "Second LienTerm Loan Exchange") and the issuance of warrants to purchase our common shares. The terms of the indenture governing the 1.5 Lien Notes and the creditagreement governing the 1.75 Lien Term Loans allow for interest payments in cash, common shares or, in certain circumstances, additional indebtedness(such interest payments in common shares or additional indebtedness, "PIK Payments"), subject to certain restrictions and limitations. Concurrently with theissuance of the 1.5 Lien Notes and as a condition precedent thereto, on March 15, 2017, we amended our credit agreement ("EXCO Resources CreditAgreement") to,2Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.among other things, permit the issuance of the 1.5 Lien Notes and the exchanges of Second Lien Term Loans, reduce the borrowing base thereunder to $150.0million and modify certain financial covenants. See further discussion of these transactions as part of "Note 5. Debt" in the Notes to our ConsolidatedFinancial Statements. The principal purpose of issuing the 1.5 Lien Notes and the Second Lien Term Loan Exchange was to alleviate our substantial cashinterest payment burden and improve our Liquidity. Our initial expectation was to make PIK Payments in common shares on the 1.5 Lien Notes and the 1.75Lien Term Loans throughout the remainder of 2017 and 2018. On June 20, 2017, we paid interest on the 1.75 Lien Term Loans in common shares, whichresulted in the issuance of 2,745,754 common shares ("PIK Shares"). On September 20, 2017, we paid $17.0 million and $26.2 million of interest on the 1.5Lien Notes and 1.75 Lien Term Loans, respectively, through the issuance of additional 1.5 Lien Notes and 1.75 Lien Term Loans. However, certainlimitations and restrictions within our debt agreements prevented us from making PIK Payments in subsequent periods.In order to improve our Liquidity, we entered into a purchase and sale agreement on April 7, 2017 to divest our oil and natural gas properties andsurface acreage in South Texas for a total purchase price of $300.0 million, subject to customary closing conditions and adjustments. However, we were notable to meet the closing conditions due to the alleged termination of a long-term natural gas sales contract that was required to be in full force and effect as ofthe closing date. As a result, the purchase and sale agreement was terminated as of August 15, 2017. We are currently in litigation with the party to the naturalgas sales contract as a result of their alleged termination of the contract. See further discussion of this transaction as part of "Note 3. Acquisitions, divestituresand other significant events" in the Notes to our Consolidated Financial Statements.On September 7, 2017, we announced that our Board of Directors delegated authority to the Audit Committee of the Board of Directors ("AuditCommittee") to explore strategic alternatives to strengthen our balance sheet and maximize the value of the Company, which included, but was not limitedto, seeking a comprehensive out-of-court restructuring or reorganization under Chapter 11 of the Bankruptcy Code. At the direction of the Audit Committee,we retained PJT Partners LP as financial advisors and Alvarez & Marsal North America, LLC as restructuring advisors, and continued to engage Kirkland &Ellis LLP as legal advisors to assist the Company with the restructuring process. We initiated discussions with our stakeholders to evaluate the feasibility of aconsensual in-court or out-of-court restructuring.Due to liquidity constraints and limitations and restrictions on our ability to pay interest in cash, commons shares or additional indebtedness, we didnot make our interest payment on the 1.75 Lien Term Loans that was due on December 20, 2017 or the interest payment on the Second Lien Term Loans thatwas due on December 26, 2017. In anticipation of certain events of default related to compliance with financial covenants and the failure to pay interest oncertain debt instruments, we entered into agreements with certain holders of the EXCO Resources Credit Agreement, 1.5 Lien Notes, and 1.75 Lien TermLoans to forbear from exercising their rights and remedies as a result of an event of default under the debt instruments until January 15, 2018.Despite our significant efforts to improve our financial condition, we continued to face increasing liquidity concerns. As of December 31, 2017, ourLiquidity was $55.5 million. On January 15, 2018, the Company and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of theBankruptcy Code. We were not able to reach an agreement with our creditors for a plan of reorganization prior to commencement of the Chapter 11 Cases.Therefore, the outcome of the Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors outside of our control, includingactions of the Court and our creditors.On January 22, 2018, we closed a Debtor-in-Possession Credit Agreement (“DIP Credit Agreement”) with lenders including affiliates of FairfaxFinancial Holdings Limited ("Fairfax"), Bluescape Resources Company LLC ("Bluescape") and JPMorgan Chase Bank, N.A. (collectively the "DIP Lenders").The DIP Credit Agreement includes a senior secured debtor-in-possession revolving credit facility in an aggregate principal amount of $125.0 million(“Revolver A Facility”) and a senior secured debtor-in-possession revolving credit facility in an aggregate principal amount of $125.0 million (“Revolver BFacility”, and together with the Revolver A Facility, the “DIP Facilities”). The proceeds from the DIP Facilities were used to refinance all obligationsoutstanding under the EXCO Resources Credit Agreement and will provide additional liquidity to fund our operations during the Chapter 11 process. Seefurther discussion of the DIP Credit Agreement in "Note 17. Subsequent events" in the Notes to our Consolidated Financial Statements.We continue to engage in discussions with our creditors regarding the terms of a financial restructuring plan. In conjunction with this process, we willexplore potential strategic alternatives to maximize value for the benefit of our stakeholders, which may include a sale of certain or substantially all of ourassets under Section 363 of the Bankruptcy Code, a plan of reorganization to equitize certain indebtedness as an alternative to the sale process, or acombination thereof.3Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Our strengthsHigh quality asset base in attractive regionsOur core areas have an extensive inventory of drilling opportunities that provide the option to allocate capital to enhance our returns in variouscommodity price environments. In addition, a significant portion of our acreage is held-by-production, which allows for the development of these propertieswithin an optimum time frame. We hold significant acreage positions in three prominent oil and natural gas regions in the United States:•East Texas and North Louisiana - we currently hold approximately 84,900 net acres in the Haynesville and Bossier shales;•South Texas - we currently hold approximately 49,700 net acres in the Eagle Ford shale; and•Appalachia - we held approximately 125,600 net acres prospective for the Marcellus shale and approximately 40,000 net acres prospective for theUtica shale predominantly located in the dry gas window as of December 31, 2017. On February 27, 2018, we closed a settlement agreement with awholly owned subsidiary of Royal Dutch Shell, plc, ("Shell") to resolve arbitration regarding our right to participate in an area of mutual interestin the Appalachia region ("Appalachia JV Settlement"). The settlement approximately doubled our interests in the aforementioned acreage in theAppalachia region. See further discussion of this settlement as part of "Note 17. Subsequent events" in the Notes to our Consolidated FinancialStatements.Our properties are generally characterized by:•multi-year inventory of development drilling and exploitation projects;•high drilling success rates;•significant unproved reserves and resources; and•long reserve lives.We have extensive amounts of technical and operational expertise within the Haynesville and Bossier shales. We have accumulated significantamounts of contiguous acreage and are one of the largest operators within this region. Our economies of scale and operational expertise have allowed us toefficiently develop our assets and minimize our costs through greater utilization of multi-well pads and existing infrastructure and facilities. We are dedicatedto the continuous improvement and innovation of well designs in order to maximize our return on capital. In recent years, we have achieved improvements inwell performance through the use of extended laterals, increased use of proppant and other changes to our completion design.We have applied our technical and operational expertise from other shale plays to our development of the Eagle Ford shale. We have realizedsignificant improvements in our drilling performance, and the optimization of our well design has yielded strong results.Our position in the Marcellus and Utica shales requires low maintenance capital as a substantial portion of our acreage is held-by-production, whichgives us flexibility to control the timing of our development activities in the region.Operational controlWe operate a significant portion of our properties, which allows us to manage our operating costs and better control capital expenditures as well as thetiming of development and exploitation activities. Therefore, we are able to allocate our capital to the most attractive projects based on commodity prices,rates of return and industry trends. As of December 31, 2017, we operated 869 of our 1,181 gross wells, or wells representing approximately 91% of ourProved Developed Reserves.Skilled technical personnel and experienced teamOur management team has extensive industry experience in acquiring, exploring, exploiting and developing oil and natural gas properties. We havedeveloped a workforce of highly skilled technical and operational personnel who have been successful in developing our shale resources. We leverage ourtechnical expertise to exploit our asset base in an efficient and cost-effective manner. We believe our technical expertise gives us a competitive advantage inour key operating areas.4Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Development plans for 2018Our plans for 2018 include a limited development program focused on the Haynesville shale in North Louisiana and the Eagle Ford shale in SouthTexas. The development of the Haynesville shale includes limited drilling and the completion of certain wells drilled in the prior year. Our developmentprogram for the Eagle Ford shale includes the drilling and completion of certain wells that will preserve the value of certain acreage with leaseholdobligations. Our development plans also include limited capital allocated to participate in the development of non-operated wells, maintenance capital andleasehold costs. The capital expenditures associated with the development plans are highly concentrated in the first half of 2018.Summary of geographic areas of operationsThe following tables set forth summary operating information attributable to our principal geographic areas of operation as of December 31, 2017:Areas Total Proved Reserves (Bcfe) (1) PV-10 (in millions) (1) (2) Average daily net production(Mmcfe/d) (3)North Louisiana 318.3 $226.8 175East Texas 68.1 65.8 36South Texas 66.3 132.5 18Appalachia and other 114.2 57.7 26Total 566.9 $482.7 255Areas Total gross acreage Total net acreageNorth Louisiana 102,300 56,000East Texas 111,600 42,100South Texas 103,000 49,700Appalachia and other 398,300 180,700Total 715,200 328,500(1)The total Proved Reserves and PV-10 as of December 31, 2017 were prepared in accordance with the rules and regulations of the Securities and Exchange Commission("SEC").(2)The PV-10 data used in this table was based on reference prices using the simple average of the spot prices for the trailing 12 month period using the first day of eachmonth beginning on January 1, 2017 and ending on December 1, 2017, of $2.98 per Mmbtu for natural gas and $51.34 per Bbl for oil, in each case adjusted forgeographical and historical differentials. Market prices for oil and natural gas are volatile (see “Item 1A. Risk Factors - Risks Relating to Our Business”). We believe thatPV-10, while not a financial measure in accordance with generally accepted accounting principles in the United States ("GAAP"), is an important financial measure usedby investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions due to taxcharacteristics which can differ significantly among comparable companies. The total Standardized Measure, a measure recognized under GAAP, as of December 31,2017 was $482.7 million. The Standardized Measure represents the PV-10 after giving effect to income taxes and is calculated in accordance with the FinancialAccounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 932, Extractive Activities, Oil and Gas ("ASC 932"). Our tax basis in theassociated properties exceeded the pre-tax cash inflows and, as a result, there is no difference in Standardized Measure and PV-10 for all years presented. The amount ofestimated future plugging and abandonment costs, the PV-10 of these costs and the Standardized Measure were determined by us. We do not designate our derivativefinancial instruments as hedges and accordingly, do not include the impact of derivative financial instruments when computing the Standardized Measure.(3)The average daily net production rate was calculated based on the average daily rate during the final month of the year ended December 31, 2017.5Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Our development and exploitation project areasEast Texas and North LouisianaOur operations in East Texas and North Louisiana are focused on the Haynesville and Bossier shales, which are primarily located in Shelby, Harrison,Panola, San Augustine and Nacogdoches Counties in Texas and DeSoto and Caddo Parishes in Louisiana. Our acreage in this region is predominantly held-by-production. The Haynesville shale is located at depths of 12,000 to 14,500 feet and is being developed with horizontal wells that typically have 4,500 to10,000 foot laterals. The lateral lengths of future wells to be drilled in this region are dependent on factors including our acreage position and nearby existingwells. The Bossier shale lies just above certain portions of the Haynesville shale and also contains rich deposits of natural gas. The geographic position of ourproperties in the Haynesville and Bossier shales provides us access to nearby markets with favorable natural gas price indices compared to the rest of thecountry.North LouisianaOur position in the Holly area of North Louisiana consists of 30,700 net acres in DeSoto Parish and 12,800 net acres in Caddo Parish, which arepredominantly held-by-production. At December 31, 2017, we had a total of 425 gross (232.9 net) operated wells flowing to sales. Our development activitiesin North Louisiana during 2017 featured a modified Haynesville shale well design, which included the use of approximately 3,500 pounds of proppant perlateral foot and lateral lengths ranging from 4,500 to 10,000 feet. We drilled 29 gross (17.9 net) operated wells and turned-to-sales 12 gross (8.4 net) operatedwells in the Haynesville shale during 2017. As of December 31, 2017, we had 17 gross (9.3 net) wells that were drilled and waiting on completion or invarious stages of the completion process. Including non-operated volumes, our average natural gas production was approximately 175 net Mmcfe per dayduring December 2017.We plan to drill 1 gross (0.7 net) operated well in the Haynesville shale during the first quarter of 2018. We plan to complete 11 gross (6.7 net)operated wells in the Haynesville shale during the first quarter of 2018, which consists of wells drilled in prior year. As a result, we will have 7 gross (3.3 net)operated wells in the Haynesville shale that will be waiting on completion at the end of the first quarter of 2018. Due to capital constraints, these wells are notexpected to be completed until 2019.6Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.East TexasOur operations in East Texas are focused on the Haynesville and Bossier shales. Our acreage is primarily located in Harrison, Panola, Shelby, SanAugustine and Nacogdoches Counties in Texas and is predominantly held-by-production. The Haynesville and Bossier shales in East Texas are beingdeveloped with horizontal wells that typically have 6,000 to 7,500 foot laterals. Our position in the Shelby area of East Texas primarily consists of 31,400net acres and includes approximately 9,800 net acres subject to continuous drilling obligations. We plan to drill, or participate with another operator indrilling, on the acreage subject to the continuous drilling obligation in the future to hold the acreage. Excluding the acreage subject to the continuousdrilling obligation, approximately 91% of our net acres are held-by-production in the Shelby area.As of December 31, 2017, we had a total of 104 gross (47.0 net) operated wells flowing to sales. Our development in this region during 2017 waslimited to the participation in certain non-operated wells. Including non-operated volumes, our average natural gas production was approximately 36 netMmcfe per day during December 2017.Our plans for 2018 include the participation in non-operated wells that will satisfy our continuous drilling obligation in the southern portion of theregion. In addition, we plan to participate in certain non-operated wells to evaluate the potential for modifications to our spacing and extent of developmentin the Haynesville and Bossier shales.South TexasOur position in this region includes approximately 49,700 net acres, of which approximately 93% are held-by-production. Our South Texas acreagecovers portions of Zavala, Dimmit and Frio Counties. Our acreage in the Eagle Ford shale is in the oil window and averages 375 feet in gross thickness at truevertical depths ranging from 5,400 to 6,800 feet. Our lateral lengths range from 5,000 to 10,000 feet and the total measured depth averages 14,600 feet. Ouracreage in the area also includes additional upside in formations such as the Austin Chalk, Buda, Georgetown and Pearsall formations.As of December 31, 2017, we had a total of 225 gross (97.6 net) operated horizontal wells flowing to sales. Including non-operated volumes, ouraverage oil production in South Texas was approximately 3,000 net barrels of oil equivalent per day during December 2017. We entered into an agreement todivest our assets in South Texas during 2017; however, the sale was not consummated since we were not able to satisfy certain closing conditions due to thealleged termination of a long-term natural gas sales contract that was required to be in full force and effect as of the closing date. We did not allocatedevelopment capital to this region during 2017 in anticipation of the potential sale. In late 2017, we initiated a limited development program that includeddrilling 2 gross (1.6 net) wells and plan to continue development in this region during 2018.We plan to drill 10 gross (8.0 net) and turn-to-sales 12 gross (9.6 net) operated wells in the Eagle Ford shale during 2018. Our development program inthis region is designed to preserve the value of certain acreage with leasehold obligations, primarily due to lease expirations, continuous drilling obligationsand offset well obligations. The development is primarily focused on Zavala and Frio Counties.Appalachia Our operations in the Appalachia region have primarily included testing and selectively developing the Marcellus shale with horizontal drilling. As ofDecember 31, 2017, we held approximately 177,700 net acres in the Appalachia region, including approximately 125,600 net acres prospective for theMarcellus shale and approximately 40,000 net acres prospective for the dry gas window of the Utica shale in Pennsylvania. Drilling, completion andproduction activities in Pennsylvania target the Marcellus shale as well as deeper formations including the Utica shale at depths ranging from 5,000 to morethan 12,000 feet. Approximately 92% of our acreage is held-by-production, which allows us to control the timing of the development of this region.7Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.As of December 31, 2017, we operated a total of 115 gross (41.0 net) horizontal wells in the Marcellus shale. We did not allocate development capitalto this region during 2017. Including non-operated volumes, our production in the Appalachia region was approximately 26 net Mmcfe per day duringDecember 2017. In recent years, we have limited our development of the Marcellus shale due to wide regional natural gas price differentials. Thesedifferentials continue to be volatile; however, the differentials in the region have the potential to be favorably impacted by the expansion of infrastructureand other sources of demand for natural gas in the Northeast region in future years. We have an extensive inventory of undeveloped locations prospective forthe Marcellus and Utica shales that has potential to provide attractive rates of return in an improved commodity price environment. Our plans for 2018 arelimited to turning-to-sales 1 gross (0.5 net) well in Sullivan County, Pennsylvania that was drilled in prior years. We do not have any producing wells in thedry gas window of the Utica shale; however, we are currently assessing the potential of the formation to determine the extent of future development.On February 27, 2018, we closed a settlement agreement with a subsidiary of Shell to resolve arbitration regarding our right to participate in an area ofmutual interest in the Appalachia region. The settlement increased our acreage in the Appalachia region by approximately 177,700 net acres, and theproduction from the additional interests in producing wells acquired was 26 net Mmcfe per day during December 2017. See further discussion of thissettlement as part of "Note 17. Subsequent events" in the Notes to our Consolidated Financial Statements.Our hydraulic fracturing activitiesOil and natural gas may be recovered from our properties through the use of sophisticated drilling and hydraulic fracturing techniques. Hydraulicfracturing involves the injection of water, sand, gel and chemicals under pressure into formations to fracture the surrounding rock and stimulate production.Our hydraulic fracturing activities are primarily focused in the Eagle Ford shale in South Texas, Haynesville and Bossier shales in East Texas and NorthLouisiana and Marcellus shale in the Appalachia region. Predominantly all of our Proved Reserves are associated with shale assets in these areas.Although the cost of each well will vary, the costs associated with the hydraulic fracturing portion of the well on average represent the followingpercentages of the total costs of drilling and completing a well: 35-40% in the Haynesville and Bossier shale formation; 30-40% in the Eagle Ford shaleformation; and 25-35% in the Marcellus shale formation. These costs may increase in future periods as a result of higher levels of proppant utilized in thecompletion of our shale wells.We review best practices and industry standards to comply with regulatory requirements in the protection of potable water sources when drilling andcompleting our wells. Protective practices include, but are not limited to, setting multiple strings of protection pipe across potable water sources andcementing these pipe strings to surface, continuously monitoring the hydraulic fracturing process in real time and disposing of non-recycled produced fluidsin authorized disposal wells at depths below the potable water sources. In addition, we actively seek methods to minimize the environmental impact of ourhydraulic fracturing operations in all of our operating areas.For more information on the risks of hydraulic fracturing, see “Item 1A. Risk Factors - Our business exposes us to liability and extensive regulation onenvironmental matters, which could result in substantial expenditures” and “Item 1A. Risk Factors - Federal, state and local legislation and regulatoryinitiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays".8Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Our oil and natural gas reservesOur Proved Reserves as of December 31, 2017 were approximately 566.9 Bcfe, of which approximately 68% were located in the Haynesville/Bossiershales, 20% in the Marcellus shale and 12% in the Eagle Ford shale.The following table summarizes our Proved Reserves as of December 31, 2017, 2016 and 2015. This information was prepared in accordance with therules and regulations of the SEC. The comparability of our reserves is impacted by commodity prices, purchases and sales of reserves in place, production,revisions of previous estimates, changes in our development plans, and discoveries and extensions. See "Management's discussion and analysis of oil andnatural gas reserves" for a summary of the changes in our Proved Reserves. As of December 31, 2017 (3) 2016 (3) 2015Oil (Mbbls) Developed 9,412 10,168 12,056Undeveloped — — 8,383Total 9,412 10,168 20,439 Natural gas (Mmcf) Developed 510,451 415,719 364,932Undeveloped — — 419,742Total 510,451 415,719 784,674 Equivalent reserves (Mmcfe) Developed 566,924 476,727 437,268Undeveloped — — 470,040Total 566,924 476,727 907,308 PV-10 (in millions) (1) Developed $482.7 $310.9 $359.4Undeveloped — — 42.7Total $482.7 $310.9 $402.1 Standardized Measure (in millions) (2) $482.7 $310.9 $402.1(1)The PV-10 is based on the following average spot prices, in each case adjusted for historical differentials. Prices presented on the table below are the trailing 12 monthsimple average spot price at the first of the month for natural gas at Henry Hub and West Texas Intermediate ("WTI") crude oil at Cushing, Oklahoma. Average spot prices Oil (per Bbl) Natural gas (per Mmbtu)December 31, 2017 $51.34 $2.98December 31, 2016 42.75 2.48December 31, 2015 50.28 2.59(2)There is no difference in Standardized Measure and PV-10 for all years presented as our tax basis in the associated properties exceeded the pre-tax cash inflows. Webelieve that PV-10, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and natural gasproducers for evaluating the relative significance of oil and natural gas properties and acquisitions due to tax characteristics, which can differ significantly amongcomparable companies. The Standardized Measure represents the PV-10 after giving effect to income taxes, and is calculated in accordance with ASC 932.(3)All of our Proved Undeveloped Reserves were reclassified to unproved reserves during 2016 due to the uncertainty regarding the financing required to develop thesereserves. These reserves remained classified as unproved due to our inability to meet the Reasonable Certainty criteria for recording Proved Undeveloped Reserves, asprescribed under the SEC requirements, as the uncertainty regarding our availability of capital required to develop these reserves still existed at December 31, 2017 and2016. We have a significant amount of reserves that would meet the criteria to be classified as Proved Undeveloped Reserves if we were able to demonstrate the financialcapability to execute a development plan.9Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Management has established, and is responsible for, internal controls designed to provide reasonable assurance that the estimates of Proved Reservesare computed and reported in accordance with rules and regulations promulgated by the SEC as well as established industry practices used by independentengineering firms and our peers. These internal controls include documented process workflows and qualified professional engineering and geologicalpersonnel with specific reservoir experience. Our internal processes and controls surrounding this process are routinely tested. We also retain outsideindependent engineering firms to prepare estimates of our Proved Reserves. Senior management reviews and approves our reserve estimates, whether preparedinternally or by third parties. Our Strategic Development and Reserves Director oversaw our outside independent engineering firms, Netherland, Sewell &Associates, Inc. ("NSAI"), and Ryder Scott Company, L.P. ("Ryder Scott") in connection with the preparation of their estimates of our Proved Reserves as ofDecember 31, 2017. We also regularly communicate with our outside independent engineering firms throughout the year regarding technical and operationalmatters critical to our reserve estimations. Our Strategic Development and Reserves Director has over 13 years of experience in the oil and natural gasindustry with a focus on reserves valuation. He is a graduate of the University of Oklahoma with dual degrees in Energy Management and Finance. Inaddition, he is an active participant in industry reserves seminars and professional industry groups. Our Chief Operating Officer and our StrategicDevelopment and Reserves Director, with input from other members of senior management, are responsible for the selection of our third-party engineeringfirms and review the reports generated by such firms. Our Chief Operating Officer has over 26 years of experience in the oil and natural gas industry and is agraduate of Texas Tech University with a degree in Petroleum Engineering. During his career, he has had multiple responsibilities in technical or leadershiproles including asset management, drilling and completions, production engineering, reservoir engineering and reserves management, economic evaluationsand field development in U.S. onshore and international projects. The third-party engineering reports are also provided to the Audit Committee.Our estimated Proved Reserves and future net cash flows for our shale properties in all regions except South Texas were prepared by NSAI as ofDecember 31, 2017, 2016 and 2015. Our estimated Proved Reserves and future net cash flows for our shale properties in the South Texas region were preparedby Ryder Scott as of December 31, 2017, 2016 and 2015. During 2016, we sold substantially all of our remaining non-shale properties. The estimates ofProved Reserves and future net cash flows for our non-shale properties as of December 31, 2015 were prepared by Lee Keeling and Associates, Inc. ("LeeKeeling"). Differences may exist between reserve quantities and values as presented in this Form 10-K and the reports of third party engineering firms filedherewith due to the exclusion of certain properties from the reports of third party engineering firms and immaterial differences in the calculations performedby the reserves evaluation software utilized by management and the third party engineering firms for estimating reserves and values.NSAI, Ryder Scott and Lee Keeling are independent petroleum engineering firms that perform a variety of reserve engineering and valuationassessments for public and private companies, financial institutions and institutional investors. NSAI, Ryder Scott and Lee Keeling have performed theseservices for over 50 years. Our internal technical employees responsible for reserve estimates and interaction with our independent engineers includeemployees and corporate officers with petroleum and other engineering degrees and relevant industry experience.Estimates of oil and natural gas reserves are projections based on a process involving an independent third party engineering firm's communicationwith EXCO's engineers and geologists, the collection of any and all required geological, geophysical, engineering and economic data, and such firm'scomplete external preparation of all required estimates and are forward-looking in nature. These reports rely on various assumptions, including definitionsand economic assumptions required by the SEC, including the use of constant oil and natural gas pricing, use of current and constant operating costs andcapital costs. We also make assumptions relating to availability of funds and timing of capital expenditures for development of our Proved UndevelopedReserves. These reports should not be construed as the current market value of our Proved Reserves. The process of estimating oil and natural gas reserves isalso dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, wecannot ensure that the Proved Reserves will ultimately be realized. Our actual results could differ materially. See “Note 16. Supplemental information relatingto oil and natural gas producing activities (unaudited)” in the Notes to our Consolidated Financial Statements for additional information regarding our oiland natural gas reserves and the Standardized Measure.NSAI, Ryder Scott and Lee Keeling also examined our estimates with respect to reserve categorization, using the definitions for Proved Reserves setforth in SEC Regulation S-X Rule 4-10(a) and SEC staff interpretations and guidance. In preparing an estimate of our Proved Reserves and future net cashflows attributable to our interests, NSAI, Ryder Scott and Lee Keeling did not independently verify the accuracy and completeness of information and datafurnished by us with respect to ownership interests, oil and natural gas production, well test data, historical costs of operation and development, productprices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of the examinationanything came to the attention of NSAI, Ryder Scott or Lee Keeling, which brought into question the validity or sufficiency of any such information or data,NSAI, Ryder Scott or Lee Keeling did not rely on such information or10Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.data until they had satisfactorily resolved their questions relating thereto or had independently verified such information or data. NSAI, Ryder Scott and LeeKeeling determined that their estimates of Proved Reserves conform to the guidelines of the SEC, including the criteria of Reasonable Certainty, as it pertainsto expectations about the recoverability of Proved Reserves in future years, under existing economic and operating conditions, consistent with the definitionin Rule 4-10(a)(24) of SEC Regulation S-X.Management's discussion and analysis of oil and natural gas reservesThe following discussion and analysis of our proved oil and natural gas reserves and changes in our Proved Reserves is intended to provide additionalguidance on the operational activities, transactions, economic and other factors which significantly impacted our estimate of Proved Reserves as ofDecember 31, 2017 and changes in our Proved Reserves during 2017. This discussion and analysis should be read in conjunction with “Note 16.Supplemental information relating to oil and natural gas producing activities (unaudited)” in the Notes to our Consolidated Financial Statements, and in“Item 1A. Risk Factors” addressing the uncertainties inherent in the estimation of oil and natural gas reserves elsewhere in this Annual Report on Form 10-K.The following table summarizes the changes in our Proved Reserves from January 1, 2017 to December 31, 2017. Oil (Mbbls) Natural gas(Mmcf) Equivalentnatural gas(Mmcfe)Proved Developed Reserves 9,412 510,451 566,924Proved Undeveloped Reserves — — —Total Proved Reserves 9,412 510,451 566,924The changes in reserves for the year are as follows: January 1, 2017 10,168 415,719 476,727Purchases of reserves in place — 50,456 50,456Discoveries and extensions 13 21,880 21,958Revisions of previous estimates: Changes in price 679 30,200 34,274Other factors (290) 72,332 70,593Sales of reserves in place — — —Production (1,158) (80,136) (87,084)December 31, 2017 9,412 510,451 566,924Purchases of reserves in placePurchases of reserves in place primarily related to the acquisition of incremental interests in certain oil and natural gas properties that we operate andundeveloped acreage in the North Louisiana region. The acquisitions increased Proved Reserves by 50.5 Bcfe during for the year ended December 31, 2017.Our Proved Reserves will increase in the future as a result of the Appalachia JV Settlement that closed on February 27, 2018. The Proved Reserves related tothe Appalachia JV Settlement were approximately 114.2 Bcfe as of December 31, 2017.Discoveries and extensionsProved Reserve additions from discoveries and extensions were 22.0 Bcfe for the year ended December 31, 2017, primarily due to the development ofthe Haynesville and Bossier shales in North Louisiana.Revisions of previous estimatesOur revisions of previous estimates included upward revisions to our Proved Reserve quantities of 104.9 Bcfe. The increase in commodity pricescontributed to 34.3 Bcfe of the upward revisions, which extended the economic life of certain producing properties when using prices prescribed by the SEC.This change in price was primarily driven by the increase in the trailing 12 month average of oil and natural gas prices. The trailing 12 month average oilprice increased from $42.75 per Bbl for the year ended December 31, 2016 to $51.34 per Bbl for the year ended December 31, 2017 and the trailing 12 monthaverage natural gas price increased from $2.48 per Mmbtu for the year ended December 31, 2016 to $2.98 per Mmbtu for the year ended December 31, 2017.11Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.In addition, our revisions of previous estimates included 70.6 Bcfe due to performance and other factors. The revisions were primarily due to thereclassification of wells to Proved Reserves during 2017 that were previously reclassified to unproved reserves in prior years due to capital constraints. Thesereclassifications primarily related to conversions of wells to Proved Developed Reserves as a result of our development activities in the North Louisianaregion.Oil and natural gas productionTotal oil and natural gas production in 2017 was 87.1 Bcfe, which included approximately 3.5 Bcfe in production from extensions and discoveriesthat were not reflected in our Proved Reserves at January 1, 2017.Proved Undeveloped ReservesAll of our Proved Undeveloped Reserves were reclassified to unproved reserves during 2016 due to the uncertainty regarding the financing required todevelop these reserves. These reserves remained classified as unproved due to our inability to meet the Reasonable Certainty criteria for recording ProvedUndeveloped Reserves, as prescribed under the SEC requirements, as the uncertainty regarding our availability of capital required to develop these reservesstill existed at December 31, 2017 and 2016. During 2017, we converted certain unproved reserves to Proved Developed Reserves as a result of our drillingand completion activities. However, we did not report any changes in our Proved Undeveloped Reserves for the year ended December 31, 2017. We have asignificant amount of reserves that would meet the criteria to be classified as Proved Undeveloped Reserves if we were able to demonstrate the financialcapability to execute a development plan.Impacts of changes in reserves on depletion rate and statements of operations in 2017Our depletion rate decreased to $0.57 per Mcfe in 2017 from $0.71 per Mcfe in 2016. The decrease was primarily due to the increase in our ProvedReserves during 2017.Our production, prices and expensesThe following table summarizes revenues, net production, average sales price per unit and costs and expenses associated with the production of oil andnatural gas. Certain reclassifications have been made to prior period information to conform to current period presentation. Year Ended December 31,(in thousands, except production and per unit amounts) 2017 2016 2015Revenues, production and prices: Oil: Revenue $57,693 $67,317 $102,787Production sold (Mbbls) 1,158 1,769 2,342Average sales price per Bbl $49.82 $38.05 $43.89Natural gas: Revenue $201,137 $181,332 $226,471Production sold (Mmcf) 80,136 93,829 109,926Average sales price per Mcf $2.51 $1.93 $2.06Costs and expenses: Oil and natural gas operating costs per Mcfe $0.40 $0.33 $0.4312Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.We had two areas that exceeded 15% of our total Proved Reserves as of December 31, 2017. The Holly field in North Louisiana and the Marcellusshale in Appalachia represented approximately 56% and 20% of our total Proved Reserves, respectively. The following table provides additional informationrelated to our Holly and Marcellus shale areas: Year Ended December 31, 2017 2016 2015Holly area: Natural gas production sold (Mmcf)53,368 55,290 73,863Average price per Mcf$2.60 $2.00 $2.18Oil and natural gas operating costs per Mcf0.32 0.23 0.22Marcellus shale: Natural gas production sold (Mmcf)9,863 10,851 12,133Average price per Mcf$2.14 $1.50 $1.39Oil and natural gas operating costs per Mcf0.17 0.12 0.22Our interest in productive wellsThe following table quantifies information regarding productive wells (wells that are currently producing oil or natural gas or are capable ofproduction), including temporarily shut-in wells. The number of total gross oil and natural gas wells excludes any multiple completions. Gross wells refer tothe total number of physical wells in which we hold a working interest, regardless of our percentage interest. A net well is not a physical well, but is a conceptthat reflects the actual total working interests we hold in all wells. We compute the number of net wells by totaling the percentage interests we hold in all ourgross wells. At December 31, 2017 Gross wells (1) Net wells Oil Natural gas Total Oil Natural gas TotalProducing region: North Louisiana — 644 644 — 246.7 246.7East Texas — 151 151 — 51.5 51.5South Texas 243 1 244 100.3 0.1 100.4Appalachia and other 2 140 142 0.1 41.4 41.5Total 245 936 1,181 100.4 339.7 440.1(1)As of December 31, 2017, we did not hold interests in any wells with multiple completions.As of December 31, 2017, we operated 869 gross (418.4 net) wells, which represented approximately 91% of our Proved Developed Reserves.13Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Our drilling activitiesOur drilling activities are primarily focused on horizontal drilling in shale plays, particularly in the Haynesville, Bossier, Eagle Ford and Marcellusshales. The following tables summarize our approximate gross and net interests in the operated wells we drilled during the periods indicated and refer to thenumber of wells completed during the period, regardless of when drilling was initiated. Development wells Gross Net Productive Dry Total Productive Dry TotalYear ended December 31, 2017 (1) 10 — 10 6.8 — 6.8Year ended December 31, 2016 (2) 15 — 15 9.2 — 9.2Year ended December 31, 2015 (3) 63 — 63 25.3 — 25.3 Exploratory wells Gross Net Productive Dry Total Productive Dry TotalYear ended December 31, 2017 (1) 2 — 2 1.6 — 1.6Year ended December 31, 2016 — — — — — —Year ended December 31, 2015 (3) 5 — 5 3.9 — 3.9(1)Our development wells in 2017 primarily included the Haynesville shale in the Holly area of North Louisiana. Our exploratory wells included the Bossier shale in theHolly area of North Louisiana.(2)Our development wells in 2016 primarily included the Haynesville and Bossier shales in the Shelby area of East Texas and the Haynesville shale in the Holly area ofNorth Louisiana.(3)Our development wells in 2015 included the Haynesville and Bossier shales in the Shelby area of East Texas and the Holly area of North Louisiana. Our developmentwells also included the Eagle Ford shale in our core area in Zavala and Frio Counties, Texas. We completed one gross exploratory well in the Bossier shale in the NorthLouisiana region and four gross exploratory wells in the Buda formation in the South Texas region.Our developed and undeveloped acreageDeveloped acreage includes those acres spaced or assignable to producing wells or wells capable of producing. Undeveloped acreage represents thoseacres that do not currently have completed wells capable of producing commercial quantities of oil or natural gas, regardless of whether the acreage containsProved Reserves. The definitions of gross acres and net acres conform to how we determine gross wells and net wells. The following table sets forth ourdeveloped and undeveloped acreage: At December 31, 2017 Developed UndevelopedArea Gross Net Gross NetNorth Louisiana 76,700 37,000 25,600 19,000East Texas 45,900 20,300 65,700 21,800South Texas 95,400 45,900 7,600 3,800Appalachia and other 48,700 18,200 349,600 162,500Total 266,700 121,400 448,500 207,100The primary terms of our oil and natural gas leases expire at various dates. Most of our undeveloped acreage is held-by-production, which means thatthese leases are active as long as there is production of oil or natural gas from wells on the acreage or certain lease terms are met. Upon ceasing production,these leases will expire. As of December 31, 2017, we had approximately 9,500; 2,300; and 3,400 net acres with lease expirations in 2018, 2019 and 2020,respectively. The majority of this acreage with lease expirations is located in the Appalachia region. In addition, we have approximately 9,800 net acreslocated in the Shelby area of East Texas that are subject to continuous drilling obligations, and we plan to drill on the acreage in the future to hold theacreage. Predominantly all of our expiring acreage is located within our shale resource plays.14Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.The held-by-production acreage in many cases represents potential additional drilling opportunities through down-spacing and drilling of provedundeveloped and unproved locations in the same formation(s) already producing, as well as other non-producing formations, in a given oil or natural gasfield without the necessity of purchasing additional leases or producing properties.Our significant customersFor the years ended December 31, 2017, 2016 and 2015, sales to BG Energy Merchants LLC, and subsequently a subsidiary of Shell, accounted forapproximately 32%, 24% and 20%, respectively, of total consolidated revenues. BG Energy Merchants LLC was a subsidiary of BG Group, plc ("BG Group")until the acquisition of BG Group by Shell in early 2016. In January 2018, we discontinued the sale of natural gas to Shell in the East Texas and NorthLouisiana regions as a result of litigation regarding certain natural gas sales contracts. See further discussion in "Item 3. Legal proceedings". We have notexperienced any interruptions or negative impact to our natural gas sales prices as a result of the discontinuance of sales to Shell in these regions. For theyears ended December 31, 2017, 2016 and 2015, Chesapeake Energy Marketing Inc. accounted for approximately 17%, 32%, and 38% respectively, of totalconsolidated revenues. Chesapeake Energy Marketing Inc. is a subsidiary of Chesapeake Energy Corporation ("Chesapeake"). We are managing our creditrisk as a result of the current commodity price environment through the attainment of financial assurances from certain customers. The loss of any significantcustomer may cause a temporary interruption in sales of, or lower price for, our oil and natural gas production.CompetitionThe oil and natural gas industry is highly competitive, particularly with respect to acquiring prospective oil and natural gas properties and oil andnatural gas reserves. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contractingfor drilling equipment and securing trained personnel. Many of these competitors have substantially greater financial, managerial, technological and otherresources than we do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas, but alsohave refining operations, market refined products and their own drilling rigs and oilfield services.The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayeddevelopment drilling and other exploitation activities and have caused significant price increases and operational delays. We may experience difficulties inobtaining drilling rigs and other services in certain areas as well as an increase in the cost for these services and related material and equipment. We areunable to predict when, or if, supply or demand imbalances may occur or how these market-driven factors impact prices, which affect our development andexploitation programs. Furthermore, our relationships with vendors may be negatively impacted by the Chapter 11 Cases, including their perception of ourfinancial condition and long-term business plans. This could further disadvantage our ability to obtain services or negatively impact the prices to obtaincertain services.The oil and gas industry has recently experienced an increase in demand for drilling and completion services as a result of the improved commodityprice environment and more efficient and effective development techniques. The domestic U.S. onshore rig count increased from 374 in May 2016 to 910 inDecember 2017. Furthermore, oil and gas companies have increased the average amount of proppant utilized in the hydraulic fracturing process to enhancerecoveries from the wells. As a result, the increased demand for drilling rigs and completion services could result in increased costs to develop our oil and gasproperties.Competition also exists for hiring experienced personnel, particularly in petroleum engineering, geoscience, accounting and financial reporting, taxand land professions. In addition, the market for oil and natural gas properties is competitive. We are often outbid by competitors in our attempts to lease oracquire properties. The oil and natural gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal andrenewable energy sources such as wind and solar power. Competitive conditions may be affected by future legislation and regulations as the U.S. developsnew energy and climate-related policies. All of these challenges could make it more difficult to execute our growth strategy or result in an increase in ourcosts.Applicable laws and regulationsGeneralThe oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Laws, orders and regulations affecting the oiland natural gas industry are under constant review for amendment or expansion, which could15Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.increase the regulatory burden and financial sanctions for noncompliance. Although the regulatory burden on the oil and natural gas industry increases ourcost of doing business and, consequently, affects our profitability, we believe these burdens do not affect us any differently or to any greater or lesser extentthan they affect others in our industry with similar types, quantities and locations of production.The following is a summary of the more significant existing environmental, safety and other laws and regulations to which our business operations aresubject and with which compliance may have a material adverse effect on our capital expenditures, earnings or competitive position.Production regulationOur operations are subject to a number of regulations at the federal, state and local levels. These regulations require, among other things, permits forthe drilling of wells, drilling bonds and reports concerning operations. Many states, counties and municipalities in which we operate also regulate one ormore of the following:•the location of wells;•the method of drilling, completing and operating wells;•the surface use and restoration of properties upon which wells are drilled;•the plugging and abandoning of wells;•notice to surface owners and other third parties; and•produced water and waste disposal.State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties.Horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are also subject towell spacing, density and proration requirements of the Texas Railroad Commission that could adversely impact our ability to maximize the efficiency of ourhorizontal wells related to reservoir drainage over time. Some states, including Louisiana and Texas, allow forced pooling or integration of tracts to facilitateexploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by thirdparties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and naturalgas wells and generally prohibit the venting or flaring of natural gas and require that oil and natural gas be produced in a prorated, equitable system. Theselaws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we candrill. Moreover, most states generally impose a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas withinits jurisdiction. Many local authorities also impose an ad valorem tax on the minerals in place. States do not generally regulate wellhead prices or engage inother, similar direct economic regulation, but there can be no assurance they will not do so in the future.Our operations are subject to numerous stringent federal and state statutes and regulations governing the discharge of materials into the environmentor otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties, as well as potential injunctiverelief, for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities andconcentrations of various substances that can be released into the environment in connection with drilling, production and transportation of oil and naturalgas, govern the sourcing, storage and disposal of water used or produced in the drilling and completion process, restrict or prohibit drilling activities incertain areas and on certain lands lying within wetlands and other protected areas, require closing earthen impoundments and impose liabilities for pollutionresulting from operations or failure to comply with regulatory filings.Statutes, rules and regulations that apply to the exploration and production of oil and natural gas are often reviewed, amended, expanded andreinterpreted, making the prediction of future costs or the impact of regulatory compliance to new laws and statutes difficult. The regulatory burden on the oiland natural gas industry increases its cost of doing business and, consequently, adversely affects its (and our) profitability.FERC and CFTC mattersThe availability, terms and cost of downstream transportation significantly affect sales of natural gas and oil. The interstate transportation of naturalgas, including regulation of the terms, conditions and rates for interstate transportation and storage of natural gas, is subject to federal regulation by theFederal Energy Regulatory Commission (“FERC”) under the Natural Gas Act (“NGA”). Transportation rates under the NGA must be just and reasonable.Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by requiring that interstate natural gas16Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.transportation be made available on an open-access, not unduly discriminatory basis. FERC’s jurisdiction under the NGA excludes gathering and distributionof natural gas; therefore, gathering and distribution of natural gas are subject to regulation by individual state laws. State regulations also govern the ratesand terms for access to, and transportation of natural gas on, intrastate pipeline facilities (while intrastate pipelines may from time to time provide specificservices that are subject to limited regulation by FERC). The interstate transportation of oil, including regulation of the rates, terms and conditions of service,is subject to federal regulation by FERC under the Interstate Commerce Act. Rates for such oil transportation must be just and reasonable and not undulydiscriminatory. Oil transportation that is not federally regulated is left to state regulation.With respect to its regulation of natural gas pipelines under the NGA, FERC has not generally required the applicant for construction of a newinterstate natural gas pipeline to produce evidence of the greenhouse gas (“GHG”) emissions of the proposed pipeline’s customers. In August 2017, the U.S.Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate application to FERC, which required FERC torevise its environmental impact statement for the proposed pipeline to take into account GHG carbon emissions from downstream power plants using naturalgas transported by the new pipeline. It is too early to determine the impacts of this Court decision, but it could be significant.The federal government recently ended its decades-old prohibition of exports of crude oil produced in the lower 48 states of the U.S. It is too recent anevent to determine the impact this regulatory change may have on our operations or our sales of oil. The general perception in the industry is that ending theprohibition on exports of oil produced in the U.S. may have a positive impact on U.S. producers. In addition, the U.S. Department of Energy (“DOE”)authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, which areexpected to increase significantly with the changes taking place in the Mexican government’s regulations of the energy sector in Mexico. In addition, theDOE authorizes the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction of which is regulated by FERC. In the thirdquarter of 2016, the first quantities of natural gas produced in the lower 48 states of the U.S. were exported as LNG from the first of several LNG exportfacilities being developed and constructed in the U.S. Gulf Coast region. While it is too recent an event to determine the impact this change may have on ouroperations or our sales of natural gas, the perception in the industry is that this will be a positive development for producers of U.S. natural gas.Wholesale prices for natural gas and oil are not currently regulated and are determined by the market. We cannot predict, however, whether newlegislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various statelegislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.Under the Energy Policy Act of 2005, FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportationactivities of natural gas market participants other than intrastate pipelines. The Commodity Futures Trading Commission (“CFTC”) also holds authority tomonitor markets and enforce anti-market manipulation regulations with respect to the physical and financial (futures, options and swaps) energy commoditiesmarket pursuant to the Commodity Exchange Act, as amended by the Dodd Frank Wall Street Reform and Consumer Protection Act of 2010. With regard toour physical sales of natural gas and oil, our gathering of any of these energy commodities, and any related hedging activities that we undertake, we arerequired to observe these anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold substantialenforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and torecommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damageclaims by, among others, sellers, royalty owners and taxing authorities.Federal, state or tribal oil and natural gas leasesIn the event we conduct operations on federal, state or tribal oil and natural gas leases, such operations must comply with numerous regulatoryrestrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conductedpursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management ("BLM"), Bureau of Ocean EnergyManagement, Bureau of Safety and Environmental Enforcement or other appropriate federal, state or tribal agencies.Surface Damage ActsIn addition, a number of states and some tribal nations have enacted surface damage statutes (“SDAs”). These laws are designed to compensate fordamage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators andsurface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration andoperating activities in addition to bonding17Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.requirements to compensate for damages to the surface as a result of such activities. Costs and delays associated with SDAs could impair operationaleffectiveness and increase development costs.Other regulatory matters relating to our pipeline and gathering system assets and rail transportationThe pipelines we use to gather and transport our oil and natural gas in interstate commerce are subject to regulation by the U.S. Department ofTransportation (“DOT”) under the Hazardous Liquid Pipeline Safety Act of 1979, as amended (“HLPSA”) with respect to oil, and the Natural Gas PipelineSafety Act of 1968, as amended (“NGPSA”) with respect to natural gas. The HLPSA and NGPSA govern the design, installation, testing, construction,operation, replacement and management of natural gas and hazardous liquids pipeline facilities, including pipelines transporting crude oil. Whereapplicable, the HLPSA and NGPSA also require us and other pipeline operators to comply with regulations issued pursuant to these acts that are designed topermit access to and allow copying of records and to make certain reports available and provide information as required by the Secretary of Transportation. The Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”) mandates requirements in the way that the energy industryensures the safety and integrity of its pipelines. The law applies to natural gas and hazardous liquids pipelines, including some gathering pipelines. Centralto the law are the requirements it places on each pipeline operator to prepare and implement an “integrity management program.” The Pipeline Safety Actmandates a number of other requirements, including increased penalties for violations of safety standards and qualification programs for employees whoperform sensitive tasks. The DOT has established a number of rules carrying out the provisions of this act. The DOT Pipeline and Hazardous Materials SafetyAdministration (“PHMSA”) has established a new risk-based approach to determine which gathering pipelines are subject to regulation, and what safetystandards regulated pipelines must meet. We could incur significant expenses as a result of these laws and regulations.The pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the DOT under the NGPSA, the PipelineSafety Act, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which was signed into law in January 2012. This law includes anumber of provisions affecting pipeline owners and operators that became effective upon approval, including increased civil penalties for violators ofpipeline regulations and additional reporting requirements. Most of the changes do not impact gathering lines. This legislation requires the PHMSA to issueor revise certain regulations and to conduct various reviews, studies and evaluations. In addition, the PHMSA had initially considered regulations regarding,among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation ofemergency flow restricting devices, and revision of valve spacing requirements. In October 2015, the PHMSA issued proposed new safety regulations forhazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and for operators to establish atimeline for inspections of affected pipelines following extreme weather events or natural disasters. If such revisions to gathering line regulations and liquidpipelines regulations are enacted by PHMSA, we could incur significant expenses.Any transportation of the Company’s crude oil or natural gas liquids by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s FederalRailroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180 (“HMR”), including Emergency Orders by the FRAand new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation offlammable liquids.U.S. federal taxationFederal income tax laws significantly affect our operations. The principal provisions that affect us are those that permit us, subject to certainlimitations, to deduct as incurred, rather than to capitalize and amortize, our share of the domestic “intangible drilling and development costs” and to claimdepletion on a portion of our domestic oil and natural gas properties (up to an aggregate of 1,000 Bbls per day of domestic crude oil and/or equivalent unitsof domestic natural gas). Further, the federal government may adopt tax laws and/or regulations that will possibly materially adversely affect us. For example,recently enacted tax legislation provides that net operating losses (“NOLs”) arising in tax years ending after December 31, 2017 are only deductible to theextent of 80% of our taxable income in such year. In addition, NOLs can now be carried forward indefinitely, but cannot be carried back. Other measures thathave been proposed in the past include the repeal or elimination of percentage depletion and the immediate deduction or write-offs of intangible drillingcosts. Because of the speculative nature of such measures at this time, we are unable to determine what effect, if any, future proposals would have on productdemand or our results of operations. See further discussion of the potential limitations on our ability to utilize NOLs in "Item 1A. Risk Factors" and recentchanges to tax laws and regulations in "Note 12. Income taxes" in the Notes to our Consolidated Financial Statements.18Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.U.S. environmental regulationsThe exploration, development and production of oil and natural gas, including the operation of saltwater injection and disposal wells, are subject tovarious federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing andoperating oil and natural gas wells. Federal environmental statutes to which our domestic activities are subject include, but are not limited to:•the Oil Pollution Act of 1990 (“OPA”);•the Clean Water Act of 1972 (“CWA”);•the Rivers and Harbors Act of 1899;•the Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”);•the Resource Conservation and Recovery Act (“RCRA”);•the Clean Air Act (“CAA”);•the Safe Drinking Water Act (“SDWA”);•the Toxic Substances Control Act of 1976 ("TSCA");•the Endangered Species Act of 1973 (the "ESA"); and•the National Environment Policy Act of 1969 (the "NEPA").These laws and their implementing regulations, as well as analogous state and local laws and regulations, generally restrict pollutants emitted to theair, discharges to surface waters, and disposal or other releases to surface and below ground soils and groundwater.In general, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmentalauthorities. For example, the United States Environmental Protection Agency (“EPA”) has identified environmental compliance by the energy extractionsection as one of its enforcement initiatives for fiscal years 2017-2019.Our domestic activities are subject to regulations promulgated under federal statutes and comparable state statutes. We also are subject to regulationsgoverning the handling, transportation, storage and disposal of naturally occurring radioactive materials that are found in our oil and natural gas operationsand other materials generated by our operations. Administrative, civil and criminal penalties, as well as injunctive relief, may be imposed for non-compliancewith environmental laws and regulations. Additionally, these laws and regulations may require the acquisition of permits or other governmentalauthorizations before we undertake certain activities, limit or prohibit other activities because of protected areas or species, restrict the types of substancesused in our drilling operations, impose certain substantial liabilities for the investigation and clean-up of pollution, impose certain reporting requirements,regulate remedial plugging operations to prevent future contamination, and require substantial expenditures for compliance. We cannot predict what effectfuture regulation or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from ouroperations could have on our activities.Under the CWA, which was amended and augmented by OPA, our release or threatened release of oil or hazardous substances into or upon waters ofthe United States, adjoining shorelines and wetlands and offshore areas could result in our being held responsible for: (1) the costs of removing orremediating a release; (2) administrative, civil or criminal fines or penalties; or (3) specified damages, such as loss of use, property damage and naturalresource damages. The scope of our liability could be extensive depending upon the circumstances of the release. Liability can be joint and several andwithout regard to fault. The CWA imposes restrictions and permitting requirements for discharges of pollutants as well as certain discharges of dredged or fillmaterial into waters of the United States, including certain wetlands, which may apply to various of our construction activities, as well as requirements todevelop Spill Prevention Control and Countermeasure Plans and Facility Response Plans to address potential discharges of oil into or upon waters of theUnited States and adjoining shorelines. State laws governing discharges to water also may impose restrictions and require varying civil, criminal andadministrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. TheEPA has issued final rules outlining its position on the federal jurisdictional reach over waters of the United States. This interpretation by the EPA mayconstitute an expansion of federal jurisdiction over waters of the United States. The rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals inOctober 2015 as that appellate court and several other courts hear lawsuits opposing implementation of the rule. In January 2017, the United States SupremeCourt accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. Litigation surrounding this rule isongoing. In February 2017, President Trump issued an executive order directing the agencies to begin the process of rescinding or revising the rule.19Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.CERCLA, often referred to as Superfund, and comparable state statutes, impose liability that is generally joint and several and that is retroactive forcosts of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on specified classes ofpersons for the release of a “hazardous substance” or under state law, other specified substances, into the environment. So-called potentially responsibleparties (“PRPs”) include the current and certain past owners and operators of a facility where there has been a release or threat of release of a hazardoussubstance and persons who disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA and, in somecases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the cost of such action.Liability can arise from conditions on properties where operations are conducted, even under circumstances where such operations were performed by thirdparties not under our control, and/or from conditions at third party disposal facilities where materials from operations were sent. Although CERCLA currentlyexempts petroleum (including oil and natural gas) from the definition of hazardous substance, some similar state statutes do not provide such an exemption.We cannot ensure that this exemption will be preserved in any future amendments of the act. Such amendments could have a material impact on our costs oroperations. Additionally, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA orregulated under similar state statutes. We may also be the owner or operator of sites on which hazardous substances have been released.Oil and natural gas exploration and production, and possibly other activities, have been conducted at a majority of our properties by previous ownersand operators. Materials from these operations remain on some of the properties and in certain instances may require remediation. In some instances, we haveagreed to indemnify the sellers of producing properties from whom we have acquired reserves against certain liabilities for environmental claims associatedwith the properties. We do not believe the costs to be incurred by us for compliance and remediating previously or currently owned or operated propertieswill be material, but we cannot guarantee that result.RCRA and comparable state and local programs impose requirements on the management, generation, treatment, storage, disposal and remediation ofboth hazardous and nonhazardous solid wastes. Although we believe we utilize operating and waste disposal practices that are standard in the industry,hydrocarbons or other solid wastes may have been disposed or released on or under the properties we own or lease, in addition to the locations where suchwastes have been taken for disposal. In addition, many of these properties have been owned or operated by third parties. We have not had control over suchparties' treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. We also generatehazardous and non-hazardous solid waste in our routine operations. It is possible that certain wastes generated by our operations, which are currently exemptfrom “hazardous waste” regulations under RCRA, may in the future be designated as “hazardous waste” under RCRA or other applicable state statutes andbecome subject to more rigorous and costly management and disposal requirements; these wastes may not be exempt under current applicable state statutes.For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmentalgroups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, the EPA and theenvironmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree,the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gaswastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and gas waste regulations, theConsent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Non-exempt waste is subject tomore rigorous and costly disposal requirements. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in asignificant increase in our costs to manage and dispose of waste.Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. The CAA and analogousstate and local laws require certain new and modified sources of air pollutants to obtain permits prior to commencing construction or operation. Smallersources may qualify for exemption from permit requirements or for more streamlined permitting, for example, through qualifications for permits by rule,standard permits or general permits. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additionaloperating permits. Federal and state laws designed to control hazardous (i.e., toxic) air pollutants may require installation of additional controls.Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetaryfines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to suspend or forgoconstruction, modification or operation of certain air emission sources.The EPA has issued final rules to subject oil and natural gas productions, storage, processing and transmission operations to regulation under the NewSource Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”), both programs under the CAA, and toimpose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gaswells. Beginning January 1, 2015,20Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards areapplicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific newrequirements, which became effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants andcertain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. Wecontinuously evaluate the effect these rules and amendments will have on our business.The EPA has adopted rules to regulate methane emissions, including from new and modified oil and gas production sources and natural gas processingand transmission sources, and has announced its intention to regulate methane emissions from existing oil and gas sources. The rules amend the air emissionrules for oil and natural gas sources and natural gas processing and transmission facilities to include new standards for methane. The status of futureregulation remains unclear but if adopted could require changes to our operations, including the installation of new emission control equipment.Simultaneously with the methane rules, the EPA adopted new rules governing the aggregating of multiple surface sites into a single-source of air qualitypermitting purposes, a change which could impact the applicability of permitting requirement to our operations and subject certain operations to additionalregulatory requirements. We continuously evaluate the effect of these rules on our operations. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions.Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required dueto emissions of other pollutants. These permitting provisions, to the extent applicable to our operations, could require us to implement emission controls orother measures to reduce GHG emissions and we could incur additional costs to satisfy those requirements. In addition, GHG regulations could have anadverse effect on demand for the oil and natural gas we produce.In addition, the EPA requires the reporting of GHG emissions from specified large GHG emission sources including onshore and offshore oil andnatural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities weoperate. Reporting of GHG emissions from such facilities is required on an annual basis. We will continue to incur costs associated with this reportingobligation.Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United NationsFramework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and "represent a progression" intheir intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” wassigned by the United States in April 2016 and entered into force in November 2016. The United States is one of more than 120 nations having ratified orotherwise consented to the agreement; however, this agreement does not create any binding obligations for nations to limit their GHG emissions but, rather,includes pledges to voluntarily limit or reduce future emissions. In June 2017, President Trump announced an intention to withdraw from the ParisAgreement.In late 2016, the BLM adopted rules governing flaring and venting on public and tribal lands, which could require additional equipment andemissions controls as well as inspection requirements. These rules have been challenged in court and remain in litigation. The BLM has temporarilysuspended or delayed parts of the rule until January 17, 2019. If allowed to stand, these additional regulations on our air emissions is likely to result inincreased compliance costs and additional operating restrictions on our business.ESA was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictionsmay be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act.The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. Acritical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oiland natural gas development. If we were to have a portion of our leases designated as critical or suitable habitat, it may adversely impact the value of theaffected leases.Oil and natural gas exploration and production activities on federal lands may be subject to the NEPA, which requires federal agencies, including theDepartment of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations,an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, ifnecessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Depending on themitigation strategies recommended in the Environmental Assessments or Environmental Impact Statement, we could incur added costs, which may besignificant. Reviews and decisions under NEPA are also subject to protest, appeal or litigation, any or all of21Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.which may delay or halt projects. To the extent that our exploration and development plans include leases on federal lands, the NEPA requirements have thepotential to delay or impose additional conditions upon the development of oil and natural gas projects.Hydraulic fracturing activitiesOver the past few years, there has been an increased focus on environmental aspects of hydraulic fracturing activities in the United States. Whilehydraulic fracturing is typically regulated by state oil and natural gas commissions in the United States, there have recently been a number of regulatoryinitiatives at the federal and local levels as well as by other state agencies.Nearly all of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and natural gaswells. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulateproduction. Our hydraulic fracturing activities are focused in our shale plays in South Texas, East Texas, North Louisiana and Appalachia. Predominantly allof our undeveloped properties would not be economical without the use of hydraulic fracturing to stimulate production from the well.Currently, most hydraulic fracturing activities are regulated at the state level, as the SDWA currently exempts from regulation the injection of fluids orpropping agents (other than diesel fuels) for hydraulic fracturing operations. Congress has periodically considered legislation to amend the federal SDWA toremove the exemption from regulation and permitting that is applicable to hydraulic fracturing operations and to require reporting and disclosure ofchemicals used by the oil and natural gas industry in the hydraulic fracturing process. Sponsors of bills previously introduced before the Senate and House ofRepresentatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Many states have considered oradopted legislation regulating hydraulic fracturing, including the disclosure of chemicals used in the process or the prohibition of certain hydraulicfracturing activities. These bills, or similar legislation, if adopted, could increase the possibility of litigation and establish an additional level of regulation atthe federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens, making it more difficultto perform hydraulic fracturing and increasing our costs of compliance.In addition, the EPA has recently been taking action to assert federal regulatory authority over hydraulic fracturing using diesel under the SDWA'sUnderground Injection Control Program and has issued guidance regarding its authority over the permitting of these activities. Additionally, in December2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activitiesassociated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times orareas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wellswith inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturingwastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Further, in June 2016, the EPA published an effluent limitguideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly ownedwastewater treatment plants. In 2014, the EPA published an advanced notice of public rulemaking regarding TSCA reporting of the chemical substances andmixture used in hydraulic fracturing.The BLM published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and tribal lands but, in June2016 a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule. On July 25, 2017, the BLMproposed to rescind these regulations. In December 2017, the BLM issued a final rule to rescind the earlier rulemaking on hydraulic fracturing.Local regulations, which may be preempted by state and federal regulations, have included the following which may extend to all operationsincluding those beyond hydraulic fracturing:•noise control ordinances;•traffic control ordinances;•limitations on the hours of operations; and•mandatory reporting of accidents, spills and pressure test failures.If in the course of our routine oil and natural gas operations, surface spills and leaks occur, including casing leaks of oil or other materials, we mayincur penalties and costs for waste handling, investigation and remediation and third party actions for damages. Moreover, we are only able to directlycontrol the operations of the wells that we operate. Notwithstanding our22Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.lack of control over wells owned by us but operated by others, the failure of the operator to comply with applicable environmental regulations may beattributable to us and may impose legal liabilities upon us.If substantial liabilities to third parties or governmental entities are incurred, the payment of such claims may reduce or eliminate the funds availablefor project investment or result in loss of our properties. Although we maintain insurance coverage we consider to be customary in the industry, we are notfully insured against all of these risks, either because insurance is not available or because of high premiums. Accordingly, we may be subject to liability ormay lose substantial portions of properties due to hazards that cannot be insured against or have not been insured against due to prohibitive premiums or forother reasons. The imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition andresults of operations.We do not anticipate that we will be required in the near future to expend amounts that are material in relation to our total capital expendituresprogram complying with current environmental laws and regulations. As these laws and regulations are frequently changed and are subject to interpretation,our assessment regarding the cost of compliance or the extent of liability risks may change in the future.OSHA and other regulationsTo the extent not preempted by other applicable laws, we are subject to the requirements of the federal OSHA and comparable state statutes, whereapplicable. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes,where applicable, require that we maintain and/or disclose information about hazardous materials used or produced in our operations. We believe that we arein substantial compliance with these applicable requirements and with other OSHA and comparable state requirements.Title to our propertiesWhen we acquire developed properties we conduct a title investigation, which will most often include either reviewing or obtaining a title opinion.However, when we acquire undeveloped properties, as is common industry practice, we usually conduct little or no investigation of title other than apreliminary review of local real property and/or mineral records. We will conduct title investigations and, in most cases, obtain a title opinion of localcounsel for the drill site before we begin drilling operations. We believe that the methods we utilize for investigating title prior to acquiring any property areconsistent with practices customary in the oil and natural gas industry and that our practices are adequately designed to enable us to acquire marketable titleto properties. However, some title risks cannot be avoided, despite the use of customary industry practices.Our properties are generally burdened by:•customary royalty and overriding royalty interests;•liens incident to operating agreements; and•liens for current taxes and other burdens and minor encumbrances, easements and restrictions.We believe that none of these burdens materially detract from the value of our properties or materially interfere with property used in the operation ofour business. In addition to the foregoing listed burdens, substantially all of our properties have been pledged as collateral under the DIP Credit Agreement,EXCO Resources Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans and the Second Lien Term Loans.Operational factors and insuranceOil and natural gas exploration and development involve a high degree of risk. In the event of explosions, environmental damage, or other accidentssuch as well fires, blowouts, equipment failure and human error, substantial liabilities to third parties or governmental entities may be incurred, thesatisfaction of which could substantially reduce available cash and possibly result in the loss of oil and natural gas properties. As is common in the oil andnatural gas industry, we are not fully insured against all risks associated with our business either because such insurance is not available or because webelieve the premium costs are prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our operating results, financialposition or cash flows. For further discussion on risks see “Item 1A. Risk Factors - We are exposed to operating hazards and uninsured risks that couldadversely impact our results of operations and cash flows.” We currently carry automobile liability, general liability and excess liability insurance with a combined annual limit of $72 million per occurrenceand in the aggregate. These insurance policies contain maximum policy limits and deductibles ranging from $1,000 to $25,000 that must be met prior torecovery, and are subject to customary exclusions and limitations.23Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Our automobile and general liability insurance covers us and our subsidiaries for third-party claims and liabilities arising out of lease operations and relatedactivities. The excess liability insurance is in addition to, and is triggered if the automobile and general liability insurance per occurrence limit is reached.Further, we currently carry $45 million of pollution coverage, $25 million of well control (blowout) coverage, property insurance in the amount of $178million in respect of wellhead, surface equipment, tanks, and miscellaneous items and scheduled oil lease roads coverage with deductibles ranging from$100,000 to $500,000.We require our third-party contractors to sign master service agreements in which they generally agree to indemnify us for the injury and death of theservice provider's employees as well as contractors and subcontractors that are hired by the service provider. Similarly, we agree to indemnify our third-partycontractors against claims made by our employees and our other contractors. Additionally, each party generally is responsible for damage to its own property.Our third-party contractors that perform hydraulic fracturing operations for us sign master service agreements containing the indemnificationprovisions noted above. We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulicfracturing operations. We believe that our general liability, excess liability and pollution insurance policies would cover third-party claims related tohydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies. However, these policiesgenerally will not cover fines and penalties. Further, these policies may not cover the costs and expenses related to government-mandated environmentalclean-up responsibilities, or may do so on a limited basis.Our employeesAs of December 31, 2017, we employed 168 persons. None of our employees are represented by unions or covered by collective bargainingagreements. To date, we have not experienced any strikes or work stoppages due to labor problems, and we consider our relations with our employees to besatisfactory. We also utilize the services of independent consultants and contractors.Forward-looking statementsThis Annual Report on Form 10-K contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933, as amended("Securities Act") and Section 21E of the Securities Exchange Act of 1934, as amended ("the Exchange Act"). These forward-looking statements relate to,among other things, the following:•our future financial and operating performance and results;•our business strategy;•market prices;•our future use of derivative financial instruments; and•our plans and forecasts.We have based these forward-looking statements on our current assumptions, expectations and projections about future events. We use the words“may,” “expect,” “anticipate,” “estimate,” “believe,” “continue,” “intend,” “plan,” “potential,” “project,” “budget” and other similar words to identifyforward-looking statements. The statements that contain these words should be read carefully because they discuss future expectations, contain projections ofresults of operations or our financial condition and/or state other “forward-looking” information. We do not undertake any obligation to update or revise anyforward-looking statements, except as required by applicable securities laws. These statements also involve risks and uncertainties that could cause our actualresults or financial condition to materially differ from our expectations in this Annual Report on Form 10-K and the documents incorporated herein byreference, including, but not limited to:•bankruptcy proceedings and the effect of those proceedings on our ongoing and future operations, including the actions of the Court and ourcreditors;•the outcome of potential strategic alternatives to maximize value for the benefit of our stakeholders as part of the Chapter 11 process, which mayinclude a sale of certain or substantially all of our assets under Section 363 of the Bankruptcy Code, a plan of reorganization to equitize certainindebtedness as an alternative to the sale process, or a combination thereof;•our ability to negotiate a plan of reorganization in connection with the Chapter 11 process, including the restructuring of our indebtedness;•our future cash flows and the adequacy to fund the significant costs associated with the bankruptcy process, including our ability to limit thesecosts by obtaining confirmation of a successful plan of reorganization in a timely manner;24Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.•our ability to maintain compliance with debt covenants and meet debt service obligations associated with the DIP Credit Agreement;•future capital requirements and availability of financing, including limitations on our ability to incur certain types of indebtedness under our debtagreements and to refinance or replace existing debt obligations;•fluctuations in the prices of oil and natural gas;•the availability of oil and natural gas;•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;•our ability to enter into transactions as a result of our Chapter 11 filing, including commodity derivative contracts with financial institutions andservices 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;•impact on our common shares as a result of the delisting from the New York Stock Exchange ("NYSE"), including the negative impact on our shareprice, volatility and liquidity associated with trading on over-the-counter markets;•environmental or other governmental regulations, including legislation to reduce emissions of greenhouse gases, legislation of derivativefinancial 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;•our ability and 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 satisfyobligations 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; and•our ability to continue as a going concern.We believe it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we areunable to accurately predict, or over which we have no control. We caution users of the financial statements not to place undue reliance on any forward-looking statements. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements included in this AnnualReport on Form 10-K. The risk factors noted in this Annual Report on Form 10-K provide examples of risks, uncertainties and events that may cause ouractual results to differ materially from those contained in any forward-looking statement. Please see “Item 1A. Risk Factors” for a discussion of certain risksrelated to our business, indebtedness and common shares.Our revenues, operating results and financial condition depend substantially on prevailing prices for oil and natural gas and the availability of capitalfrom the DIP Credit Agreement and other sources. Declines in oil or natural gas prices may have a material adverse effect on our financial condition,Liquidity, results of operations, the amount of oil or natural gas that we can produce economically and the ability to fund our operations. Historically, oil andnatural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.25Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Glossary of selected oil and natural gas termsThe following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and this Annual Report on Form 10-K.2-D seismic. Geophysical data that depicts the subsurface strata in two dimensions.3-D seismic. Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurateinterpretation of the subsurface strata than 2-D seismic.Appraisal wells. Wells drilled to convert an area or sub-region from the resource to the reserves category.Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth,temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus mayprovide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogousreservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) same geological formation (but not necessarilyin pressure communication with the reservoir of interest); (ii) same environment of deposition; (iii) similar geological structure; and (iv) same drivemechanism.Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs or other liquid hydrocarbons.Bbtu. One billion British thermal units.Bcf. One billion cubic feet of natural gas.Bcfe. One billion cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas. This ratio of Bbl to Mcf iscommonly used in the oil and natural gas industry and represents the approximate energy equivalent of natural gas to oil or NGLs, and does notrepresent the sales price equivalency of natural gas to oil or NGLs. Currently the sales price of a Bbl or NGL is significantly higher than the sales priceof six Mcf of natural gas.Btu. British thermal unit, which is the heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.Completion. The installation of permanent equipment for the production of oil or natural gas, or, in the case of a dry hole, the reporting to theappropriate authority that the well has been abandoned.Deterministic method. The method of estimating reserves or resources when a single value for each parameter (from the geoscience, engineering, oreconomic data) in the reserves calculation is used in the reserves estimation procedure.Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to beproductive.Dry hole; Dry well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or naturalgas well.Economically producible. As it relates to a resource, a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs ofthe operation.Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as ofthat date.Exploitation. The continuing development of a known producing formation in a previously discovered field. To maximize the ultimate recovery of oilor natural gas from the field by development wells, secondary recovery equipment or other suitable processes and technology.Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oilor natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, a service well, or a stratigraphic test well.Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.Fracture stimulation. A stimulation treatment routinely performed involving the injection of water, sand and chemicals under pressure to stimulatehydrocarbon production.26Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Full cost pool. The full cost pool consists of all costs associated with property acquisition, exploration, and development activities for a companyusing the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration anddevelopment activities are included. Any costs related to production, general corporate overhead or similar activities are not included.Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.Held-by-production. A provision in an oil, natural gas and mineral lease that perpetuates a company's right to operate a property or concession as longas the property or concession produces a minimum paying quantity of oil or natural gas.Horizontal wells. Wells drilled at angles greater than 70 degrees from vertical.Initial production rate. Generally, the maximum 24 hour production volume from a well.Mbbl. One thousand stock tank barrels.Mcf. One thousand cubic feet of natural gas.Mcfe. One thousand cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.Mmbbl. One million stock tank barrels.Mmbtu. One million British thermal units.Mmcf. One million cubic feet of natural gas.Mmcf/d. One million cubic feet of natural gas per day.Mmcfe. One million cubic feet of natural gas equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas. This ratio of Bbl toMcf is commonly used in the oil and natural gas industry and represents the approximate energy equivalent of natural gas to oil or NGLs, and does notrepresent the sales price equivalency of natural gas to oil or NGLs. Currently the sales price of a Bbl or NGL is significantly higher than the sales priceof six Mcf of natural gas. Mmcfe/d. One million cubic feet of natural gas equivalent per day calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.Net acres or net wells. Exists when the sum of fractional ownership interests owned in gross acres or gross wells equals one. We compute the numberof net wells by totaling the percentage interest we hold in all our gross wells.NYMEX. New York Mercantile Exchange.NGLs. The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels ofhigher pressure and lower temperature.Overriding royalty interest. An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of thecosts of production.Pad drilling. The drilling of multiple wells from the same site.Play. A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas withpotential oil and natural gas reserves.Present value of estimated future net revenues or PV-10. The present value of estimated future net revenues is an estimate of future net revenues froma property at the date indicated, without giving effect to derivative financial instrument activities, after deducting production and ad valorem taxes,future capital costs, abandonment costs and operating expenses, but before deducting future income taxes. The future net revenues have beendiscounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the netrevenue stream and should not be construed as being the fair market value of the properties. Estimates have been made using constant oil and naturalgas prices and operating and capital costs at the date indicated, at its acquisition date, or as otherwise indicated.Probabilistic method. The method of estimation of reserves or resources when the full range of values that could reasonably occur for each unknownparameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities ofoccurrence.Productive well. A productive well is a well that is not a dry well.Proved Developed Reserves. These reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existingequipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and(ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means notinvolving a well.Proved Reserves. Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineeringdata, can be estimated with Reasonable Certainty to be economically producible from a27Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the timeat which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whetherdeterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator mustbe reasonably certain that it will commence the project within a reasonable time.The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacentundrilled portions of the reservoir that can, with Reasonable Certainty, be judged to be continuous with it and to contain economically producible oilor gas on the basis of available geoscience and engineering data.In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a wellpenetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with Reasonable Certainty. Wheredirect observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, provedoil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliabletechnology establish the higher contact with Reasonable Certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) areincluded in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than inthe reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technologyestablishes the Reasonable Certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved fordevelopment by all necessary parties and entities, including governmental entities.Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be theaverage price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic averageof the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalationsbased upon future conditions.Proved Undeveloped Reserves. Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wellswhere a relatively major expenditure is required for recompletion.Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production whendrilled, unless evidence using reliable technology exists that establishes Reasonable Certainty of economic producibility at greater distances.Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduledto be drilled within five years, unless the specific circumstances justify a longer time.Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or otherimproved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or ananalogous reservoir or by other evidence using reliable technology establishing Reasonable Certainty.Recompletion. An operation within an existing well bore to make the well produce oil and/or natural gas from a different, separately producible zoneother than the zone from which the well had been producing.Reasonable Certainty. If deterministic methods are used, Reasonable Certainty means a high degree of confidence that the quantities will berecovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed theestimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availabilityof geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to EUR with time, reasonably certain EUR ismuch more likely to increase or remain constant than to decrease.Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined byimpermeable rock or water barriers and is individual and separate from other reservoirs.Resources. Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may beestimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscoveredaccumulations.Royalty interest. An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of the costs ofproduction.Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.28Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Shut-in well. A producing well that has been closed down temporarily for, among other things, economics, cleaning out, building up pressure, lack of amarket or lack of equipment. Spud. To start the well drilling process.Standardized Measure of discounted future net cash flows or the Standardized Measure. Under the Standardized Measure, future cash flows areestimated by applying the simple average spot prices for the trailing 12 month period using the first day of each month beginning on January 1 andending on December 1 of each respective year, adjusted for price differentials, to the estimated future production of year-end Proved Reserves. Futurecash inflows are reduced by estimated future production and development costs based on period-end and future plugging and abandonment costs todetermine pre-tax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our taxbasis in the associated properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at theStandardized Measure.Stock tank barrel. 42 U.S. gallons liquid volume.Tcf. One trillion cubic feet of natural gas.Tcfe. One trillion cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas. This ratio of Bbl to Mcf iscommonly used in the oil and natural gas industry and represents the approximate energy equivalent of natural gas to oil or NGLs, and does notrepresent the sales price equivalency of natural gas to oil or NGLs. Currently the sales price of a Bbl or NGL is significantly higher than the sales pricefor six Mcf of natural gas.Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economicquantities of oil and natural gas regardless of whether such acreage contains Proved Reserves.Working interest. The operating interest that gives the owner the right to drill, produce and conduct activities on the property and a share ofproduction.Workovers. Operations on a producing well to restore or increase production.Available informationWe make available, free of charge, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendmentsto these reports on our website at www.excoresources.com as soon as reasonably practicable after those reports and other information are electronically filedwith, or furnished to, the SEC.Item 1A.Risk FactorsThe risk factors noted in this section and other factors noted throughout this Annual Report on Form 10-K, including those risks identified in “Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations” describe examples of risks, uncertainties and events that maycause our actual results to differ materially from those contained in any forward-looking statement.If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from thoseincluded in this Annual Report on Form 10-K.Risks Relating to Our RestructuringWe have filed voluntary petitions for relief under the Bankruptcy Code and are subject to the risks and uncertainties associated with bankruptcy cases.On January 15, 2018, the Company and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. Ourbusiness and operations will be subject to various risks for the duration of the Chapter 11 proceedings, including, but not limited to, the following:•our ability to continue as a going concern;•our ability to develop, file and consummate a Chapter 11 plan of reorganization;•our ability to obtain Court, creditor and regulatory approval of a Chapter 11 plan of reorganization in a timely manner;•our ability to obtain Court approval with respect to motions in the Chapter 11 Cases and the outcomes of Court rulings and of the Chapter 11Cases in general;29Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.•the ability of third parties to file motions in our Chapter 11 Cases, which may interfere with our business operations or our ability to proposeand/or complete a Chapter 11 plan of reorganization;•increased costs related to the Chapter 11 Cases and related litigation;•our ability to obtain and maintain normal payment and other terms with customers, vendors and service providers, as well as our ability tomaintain contracts that are critical to our operations;•a loss of, or a disruption in the materials or services received from suppliers, contractors or service providers with whom we have commercialrelationships;•potential increased difficulty in retaining and motivating our key employees through the process of reorganization, and potential increaseddifficulty in attracting new employees;•significant time and effort required to be spent by our senior management in dealing with the bankruptcy and restructuring activities rather thanfocusing exclusively on business operations; and•our ability to fund and execute our business plan and our ability to obtain any necessary financing for our business on acceptable terms or at all.We are also subject to risks and uncertainties with respect to the actions and decisions of creditors and other third parties who have interests in ourChapter 11 Cases that may be inconsistent with our plans. These risks and uncertainties could affect our business and operations in various ways and maysignificantly increase the duration of the Chapter 11 Cases. For example, negative events or publicity associated with the Chapter 11 Cases could adverselyaffect our relationships with our vendors and employees, as well as with customers, which in turn could adversely affect our operations and financialcondition. Also, pursuant to the Bankruptcy Code, we need Court approval for transactions outside the ordinary course of business, which may limit ourability to respond timely to events or take advantage of opportunities.Because of the risks and uncertainties associated with the Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurringduring the Chapter 11 Cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimateimpact that events occurring during the Chapter 11 Cases may have on our corporate or capital structure.We believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 proceedings.We have a significant amount of indebtedness that is senior to our existing common shares in our capital structure. As a result, we believe it is highlylikely that our existing common shares will be canceled at the conclusion of our Chapter 11 proceedings, and the holders of our existing common shares willbe entitled to a limited recovery, if any. Any trading in our common shares during the pendency of the Chapter 11 Cases is highly speculative and posessubstantial risks to purchasers of shares of our common shares.Operating under Court protection for a long period of time may harm our business.Our future results are dependent upon the successful confirmation and implementation of a plan of reorganization. A long period of operations underCourt protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as the proceedingsrelated to the Chapter 11 Cases continue, our senior management will be required to spend a significant amount of time and effort dealing with thereorganization instead of focusing exclusively on our business operations.In conjunction with these bankruptcy proceedings, we are exploring the potential sale of certain or substantially all of our assets under Section 363 ofthe Bankruptcy Code. There can be no assurance that any such sale will be completed. The process to market our assets will result in additional uncertaintysurrounding the potential outcome of the Chapter 11 Cases and could further delay the conclusion of the Chapter 11 Cases. A prolonged period of operatingunder Court protection also may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. Inaddition, the longer the Chapter 11 Cases continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize ourbusinesses successfully and seek to establish alternative commercial relationships.During the pendency of the bankruptcy proceedings, our Liquidity will depend mainly on cash generated from operating activities and available fundsunder the DIP Credit Agreement. On January 22, 2018, we closed the DIP Credit Agreement providing for $250.0 million of debtor-in-possession financing.The proceeds from the DIP Facilities were used to refinance all obligations outstanding under the EXCO Resources Credit Agreement and will provideadditional liquidity to fund our operations during the Chapter 11 Cases.30Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.So long as the Chapter 11 Cases continue, we will be required to incur substantial costs for professional fees and other expenses associated with theadministration of the Chapter 11 Cases. Furthermore, we may experience significant costs and delays due to litigation during the Chapter 11 Cases. The DIPFacilities may not be sufficient to support our day-to-day operations in the event of a prolonged restructuring process and we may be required to seekadditional debtor-in-possession financing to fund our operations. If we are unable to obtain such financing on favorable terms or at all, our chances ofsuccessfully reorganizing our business may be seriously jeopardized, the likelihood that we instead will be required to liquidate our assets may be enhanced,and, as a result, any claims and securities in the Debtors could become further devalued or become worthless.We cannot predict the ultimate outcome for the liabilities that will be subject to a plan of reorganization. Even if a plan of reorganization is approvedand implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do businesswith a company that recently emerged from Chapter 11.We may not be able to obtain confirmation of a Chapter 11 plan of reorganization.To emerge successfully from Court protection as a viable entity, we must meet certain statutory requirements with respect to a Chapter 11 plan ofreorganization, including obtaining the requisite acceptances of such a plan, certain other statutory conditions for confirmation of such a Chapter 11 plan,which have not occurred to date. We were not able to reach an agreement with our creditors for a plan of reorganization prior to commencement of theChapter 11 Cases. Therefore, the outcome of our Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors outside of ourcontrol, including actions of the Court and our creditors. The confirmation process is subject to potential delays, which could include a delay in the Court’scommencement of the confirmation hearing regarding our plan.We may not receive the requisite acceptances of our creditors in the proceedings related to the Chapter 11 Cases to confirm a plan. Even if the requisiteacceptances of a plan are received, the Court may not confirm such a plan. The precise requirements and evidentiary showing for confirming a plan,notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation,the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims, orcommon shares).If a Chapter 11 plan of reorganization is not confirmed by the Court, it is unclear whether we would be able to reorganize our business and what, ifanything, holders of claims against us would ultimately receive with respect to their claims. Our creditors would likely incur significant costs in connectionwith developing and seeking approval of an alternative plan of reorganization, which might not be supported by any of the current debt holders, variousstatutory committees or other stakeholders. If an alternative reorganization could not be agreed upon, it is possible that we would have to liquidate our assets,in which case it is likely that holders of claims would receive substantially less favorable treatment than they would receive if we were to emerge as a viable,reorganized entity. There can be no assurance as to whether we will successfully reorganize and emerge from the Chapter 11 Cases or, if we do successfullyreorganize, as to when we would emerge from the Chapter 11 Cases.Even if a Chapter 11 plan of reorganization is consummated, we will continue to face risks.Even if a Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including certain risks that are beyond ourcontrol, such as further deterioration or other changes in economic conditions, changes in our industry, changes in prices for oil and natural gas andincreasing expenses. Some of these concerns and effects typically become more acute when a case under the Bankruptcy Code continues for a protractedperiod without indication of how or when the case may be completed. As a result of these risks and others, there is no guaranty that any plan of reorganizationwill achieve our stated goals.Furthermore, even if our debts are reduced or discharged through a plan of reorganization, we may need to raise additional funds through public orprivate debt or equity financing or other means to fund our business after the completion of the Chapter 11 process. Adequate funds may not be availablewhen needed or may not be available on favorable terms.The terms of our indebtedness include restrictions and financial covenants that may restrict our business and financing activities.The availability of borrowings under the DIP Credit Agreement is essential to our ability to fund our operations during the Chapter 11 Cases. The DIPCredit Agreement includes certain affirmative and negative covenants, including, among other covenants customary in similar reserve-based credit facilitiesand debtor-in-possession financings, requirements to maintain a31Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.minimum level of liquidity and limit our aggregate disbursements to certain thresholds compared to the 13-week cash flow forecasts provided to the DIPLenders. Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations,development activities and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply withthese covenants may be impaired. The DIP Facilities contain events of default, including: (i) conversion of the Chapter 11 Cases to cases under Chapter 7 ofthe Bankruptcy Code and (ii) appointment of a trustee, examiner or receiver in the Chapter 11 Cases.If we violate any provisions of our such financing agreements that are not cured or waived within the appropriate time periods provided therein, asignificant portion of our indebtedness may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate.We might not have, or be able to obtain, sufficient funds to make these accelerated payments. We have substantial liquidity needs and may be required to seek additional financing if we experience a prolonged bankruptcy process. If we are unable tomaintain adequate liquidity, we may not be able to obtain financing on satisfactory terms.Our principal sources of Liquidity historically have been internally generated cash flows from operations, borrowings under certain credit agreements,issuances of debt securities, dispositions of non-strategic assets, joint ventures and capital markets when conditions are favorable. Our capital programapproved for 2018 will require additional financing above the level of cash generated by our operations. As described above, we have entered into the DIPFacilities, but we cannot guarantee that the funds available under the DIP Facilities and our cash flow from operations will be sufficient to fund ouroperations if we experience a prolonged bankruptcy process.We face uncertainty regarding the adequacy of our Liquidity and capital resources and have extremely limited, if any, access to additional financing.In addition to the cash requirement necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection withpreparation for the Chapter 11 Cases and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 Cases. Wecannot provide assurance that our Liquidity will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to Chapter 11Cases until we are able to emerge from our Chapter 11.Our Liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things; (i) our ability to complywith the terms and conditions of any post-petition financing and cash collateral order entered by the Court in connection with the Chapter 11 Cases, (ii) ourability to maintain adequate cash on hand, (iii) our ability to generate cash flow from operations, (iv) our ability to develop, confirm and consummate aChapter 11 plan or other alternative restructuring transaction and (v) the cost, duration and outcome of the Chapter 11 Cases. Our ability to maintainadequate Liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control.In the event that the DIP Facilities and our cash on hand and cash flow from operations are not sufficient to meet our Liquidity needs, we may be required toseek additional financing. We can provide no assurance that additional financing would be available or, if available, offered to us on acceptable terms. Ouraccess to additional financing is, and for the foreseeable future will likely continue to be, extremely limited if it is available at all. Our long-term Liquidityrequirements and the adequacy of our capital resources are difficult to predict at this time.In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.Upon a showing of cause, the Court may convert our Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. Webelieve that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in a Chapter11 plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time ratherthan in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee and (iii)additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leasesand other executory contracts in connection with a cessation of operations. In addition, if the Chapter 11 Cases are converted to cases under Chapter 7, thatwould constitute an event of default under the DIP Credit Agreement.32Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.As a result of the Chapter 11 Cases, our historical financial information may be volatile and not be indicative of our future financial performance.During the Chapter 11 Cases, we expect our financial results under U.S. GAAP to continue to be volatile as asset impairments, asset dispositions,restructuring activities and expenses, contract terminations and rejections, and claims assessments may significantly impact our Consolidated FinancialStatements. As a result, our historical financial performance may not be indicative of our financial performance after the date of the bankruptcy filing.Our capital structure will likely be significantly altered under any Chapter 11 plan confirmed by the Court. Under fresh-start accounting rules that mayapply to us upon the effective date of a Chapter 11 plan, our assets and liabilities would be adjusted to fair value, which could have a significant impact onour financial statements. Accordingly, if fresh-start accounting rules apply, our financial condition and results of operations following our emergence fromChapter 11 would not be comparable to the financial condition and results of operations reflected in our historical financial statements. In connection withthe Chapter 11 Cases and the development of a Chapter 11 plan, it is also possible that additional restructuring and related charges may be identified andrecorded in future periods. Such charges could be material to our consolidated financial position, liquidity and results of operations.Transfers of our equity, or issuances of equity in connection with our Chapter 11 Cases, may impair our ability to utilize our federal income tax netoperating loss carryforwards in future years.Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years.We have NOLs of approximately $2.1 billion as of December 31, 2017. Our ability to utilize our NOLs to offset future taxable income and to reduce federalincome tax liability is subject to certain requirements and restrictions. If we experience an “ownership change,” as defined in Section 382 of the U.S. InternalRevenue Code, then our ability to use our net operating loss carryforwards may be substantially limited, which could have a negative impact on our financialposition and results of operations. Generally, there is an “ownership change” if one or more shareholders owning five percent or more of a corporation’scommon stock ("Substantial Shareholder") have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period.We received relief from the Court to establish notice and sell-down procedures for trading of our common shares in order to provide us with the abilityto formulate a plan of reorganization that preserves our tax attributes. Under the order, prior to any proposed acquisition or disposition of equity securitiesthat would result in an increase or decrease in the amount of our equity securities owned by a Substantial Shareholder, or that would result in a person orentity becoming a Substantial Shareholder, such person or entity is required to file with the Court and notify us of such acquisition or disposition. We havethe right to seek an injunction from the Court to prevent certain acquisitions or sales of our common shares if the acquisition or sale would pose a materialrisk of adversely affecting our ability to utilize such tax attributes.Following the implementation of a plan of reorganization, it is possible that an “ownership change” may be deemed to occur. Under Section 382 of theU.S. Internal Revenue Code, absent an application exception, if a corporation undergoes an “ownership change,” the amount of its net operating losses thatmay be utilized to offset future taxable income generally is subject to an annual limitation. If an ownership change occurs and our NOLs are subject to theSection 382 limitation, this could adversely impact our future cash flows if we have taxable income and are not able to offset it through the utilization of ourNOLs.We have significant exposure to fluctuations in commodity prices since none of our estimated future production is covered by commodity derivativecontracts and we may not be able to enter into commodity derivative contracts covering our estimated future production on favorable terms or at all.During the Chapter 11 Cases, our ability to enter into commodity derivative contracts covering estimated future production is limited under the DIPCredit Agreement. We are only permitted to enter into commodity derivative contracts with lenders under the DIP Credit Agreement. As a result, we may notbe able to enter into commodity derivative contracts covering our production in future periods on favorable terms or at all. If we cannot or choose not to enterinto commodity derivative contracts in the future, we could be more affected by changes in commodity prices. Our inability to hedge the risk of lowcommodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results ofoperations.We have and may continue to experience increased levels of employee attrition as a result of the Chapter 11 Cases.As a result of the Chapter 11 Cases, we have and may continue to experience increased levels of employee attrition, and33Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.our employees likely will face considerable distraction and uncertainty. A loss of key personnel or material erosion of employee morale could adverselyaffect our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate andincentivize key employees to remain with us through the pendency of the Chapter 11 Cases is limited by restrictions on implementation of incentiveprograms under the Bankruptcy Code. The loss of services of members of our senior management team could impair our ability to execute our strategy andimplement operational initiatives, which would be likely to have a material adverse effect on our financial condition, Liquidity and results of operations.Risks Relating to Our BusinessOil and natural gas prices, which are subject to fluctuations, have declined substantially from historical highs. Reductions in oil and natural gas priceshave, and may in the future, adversely affect our revenues as well as our ability to maintain or increase our borrowing capacity, repay current or futureindebtedness and obtain additional capital on attractive terms.Our future financial condition, access to capital, cash flow and results of operations depend upon the prices we receive for our oil and natural gas. Weare particularly dependent on prices for natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response tochanges in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including, but not limited to:•the domestic and foreign supply of oil and natural gas;•weather conditions;•the price and quantity of imports of oil and natural gas;•political conditions and events in other oil-producing and natural gas-producing countries, including embargoes, hostilities in the Middle Eastand other sustained military campaigns, and acts of terrorism or sabotage;•the actions of the OPEC;•domestic government regulation, legislation and policies;•the level of global oil and natural gas inventories;•technological advances affecting energy consumption;•the price and availability of alternative fuels and other energy sources; and•overall economic conditions.Oil and natural gas prices declined sharply during the latter half of 2014 and continued to decline throughout 2015 and into 2016. Oil and natural gasprices have recently experienced a modest recovery; however, they may never return to historical highs or remain at a level that allows us to economicallyoperate our business. Prices of oil and natural gas have historically been extremely volatile and we expect this volatility to continue.During 2017, the NYMEX Henry Hub natural gas price fluctuated from a high of $3.65 per Mmbtu to a low of $2.44 per Mmbtu, while the NYMEXWTI crude oil price ranged from a high of $60.42 per Bbl to a low of $42.53 per Bbl. For the five years ended December 31, 2017, the NYMEX Henry Hubnatural gas price ranged from a high of $7.94 per Mmbtu to a low of $1.49 per Mmbtu, while the NYMEX WTI crude oil price ranged from a high of $110.53per Bbl to a low of $26.21 per Bbl.On December 31, 2017, the spot market price for natural gas at Henry Hub was $2.97 per Mmbtu, a 20% decrease from December 31, 2016. OnDecember 31, 2017, the spot market price for crude oil at Cushing was $60.42 per Bbl, a 12% increase from December 31, 2016. For 2017, our averagerealized prices (before the impact of derivative financial instruments) for oil and natural gas were $49.82 per Bbl and $2.51 per Mcf, respectively, comparedwith 2016 average realized prices of $38.05 per Bbl and $1.93 per Mcf, respectively.Our revenues, cash flow and profitability, as well as our ability to maintain or increase our borrowing capacity, to repay current or future indebtednessand to obtain additional capital on attractive terms, depend substantially upon oil and natural gas prices. Any sustained reductions in oil and natural gasprices will directly affect our revenues and can indirectly impact expected production by changing the amount of funds available to us to reinvest inexploration and development activities. Further reductions in oil and natural gas prices could also reduce the quantities of reserves that are commerciallyrecoverable. Depressed oil and natural gas prices and reductions in our reserves could have other adverse consequences, including downwardredeterminations of the availability of borrowings under the DIP Credit Agreement, which may begin on January 1, 2019 if we elect to extend the maturity ofthe DIP Credit Agreement. Additionally, further or continued declines in prices could result in additional non-cash charges to earnings due to impairments toour oil and natural gas properties.34Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.In light of the depressed commodity price environment, there is risk that, among other things:•third parties’ confidence in our commercial or financial ability to explore and produce oil and natural gas could erode, which could impact ourability to execute on our business strategy;•it may become more difficult to retain, attract or replace key employees;•employees could be distracted from performance of their duties or more easily attracted to other career opportunities; and•our suppliers, vendors and service providers could renegotiate the terms of our arrangements, terminate their relationship with us or requirefinancial assurances from us.The occurrence of certain of these events may have a material adverse effect on our business, results of operations and financial condition.Changes in the differential between NYMEX or other benchmark prices of oil and natural gas and the reference or regional index price used to price ouractual oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.The reference or regional index prices that we use to price our oil and natural gas sales sometimes reflect a premium or discount to the relevantbenchmark prices, such as NYMEX. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. Wecannot accurately predict oil and natural gas differentials. Changes in differentials between the benchmark price for oil and natural gas and the reference orregional index price we reference in our sales contracts could have a material adverse effect on our results of operations and financial condition. We haveexperienced significant volatility in our price differentials including crude oil production from the Eagle Ford shale and natural gas production from certainareas in Appalachia. Our crude oil production from the Eagle Ford shale is currently sold at a price based on the WTI index plus or minus the differential toindices correlated to the Louisiana Light Sweet index. During 2017, the monthly average of this differential ranged from a high of WTI plus $4.19 per barrelto a low of WTI less $3.27 per barrel. Our natural gas production from the Marcellus shale in Northeast Pennsylvania is sold at a price based on a Platts indexthat represents value into the Transco Leidy Pipeline. Due to the increased production in this region without an offsetting increase in pipeline capacity orinfrastructure to the Northeast United States markets, the monthly average of this differential during 2017 ranged from a low of NYMEX less $0.44 perMmbtu to a high of NYMEX less $2.11 per Mmbtu. These differentials vary depending on factors such as supply, demand, pipeline capacity, infrastructureand weather.We may encounter obstacles to marketing our oil and natural gas, which could adversely impact our revenues.Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements or infrastructure may hinder our access to oiland natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors,including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities.Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines, processing facilitiesand oil and condensate trucking operations owned and operated by third-parties. Our failure to obtain these services on acceptable terms could have amaterial adverse effect on our business. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due torepairs, outages caused by accidents or other events, or improvements to facilities or due to space being utilized by other companies that have prioritytransportation agreements. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines,gathering systems or trucking capacity. A portion of our production may also be interrupted, or shut-in, from time to time for numerous other reasons,including as a result of accidents, excessive pressures, maintenance, weather, field labor issues or other disruptions of service. Curtailments and disruptionsmay last from a few days to several months, and we have no control over when or if third-party facilities are restored.We have experienced production curtailments in our producing regions resulting from offsetting fracturing stimulation operations. As we haveincreased our knowledge of our shale properties, we have begun to shut-in production on adjacent wells when conducting completion operations. Due to thehigh production capabilities of these wells, these volumes can be significant. Our access to transportation options can also be affected by U.S. federal andstate regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand.In our South Texas region, the primary purchaser of our natural gas allegedly terminated a long-term natural gas sales contract on May 31, 2017. Seefurther discussion of the litigation related to the purported termination of this contract in "Item 3. Legal proceedings". Our ability to transport or sell thenatural gas from this region is limited due to the existing35Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.infrastructure and we may experience significant curtailments of production if we cannot find an operational or commercial solution. After the allegedtermination of the long-term natural gas sales contract, we have either sold natural gas on short-term sales contracts or flared natural gas in order to avoidsignificant curtailments of our oil production. However, our ability and the costs associated with entering into natural gas sales contracts in the future arehighly uncertain.These factors and the availability of markets are beyond our control. Any significant curtailment in gathering, processing or pipeline system capacity,significant delay in the construction of necessary facilities or lack of availability of transportation would interfere with our ability to market our oil andnatural gas production, and could have a material adverse effect on our cash flow and results of operations.We may experience a financial loss if any of our significant customers fail to pay us for our oil or natural gas or reduce the volume of oil and natural gasthat they purchase from us.Our ability to collect payments from the sale of oil and natural gas to our customers depends on the payment ability of our customer base, whichincludes several significant customers. If any one or more of our significant customers fails to pay us for any reason, we could experience a material loss. Weare managing our credit risk as a result of the current commodity price environment through the attainment of financial assurances from certain customers. Inaddition, if any of our significant customers cease to purchase our oil or natural gas or reduce the volume of the oil or natural gas that they purchase from us,the loss or reduction could have a detrimental effect on our production volumes and may cause a temporary interruption in sales of, or a lower price for, ouroil and natural gas. We have filed a lawsuit against a subsidiary of Shell regarding their failure to remit payment under certain natural gas sales agreements inthe East Texas and North Louisiana regions, see further discussion in "Item 3. Legal proceedings".We have significant natural gas firm transportation and marketing agreements primarily in East Texas and North Louisiana that require us to pay fixedamounts of money to the shippers or marketers regardless of quantities actually shipped or marketed. Our results of operations and Liquidity could beadversely affected if we are required to pay for shortfall amounts under these contracts.We have significant natural gas firm transportation contracts primarily in North Louisiana that require us to pay fixed amounts of money to theshippers regardless of quantities actually shipped. The use of firm transportation agreements allows us priority space in a shippers’ pipeline. Historically, wehave paid significant amounts for the unused portion of these firm transportation agreements. These contracts include a natural gas sales contract withEnterprise Products Operating LLC (“Enterprise”) and a firm transportation agreement with Acadian Gas Pipeline System (“Acadian”) that are currently inlitigation. See further discussion of the litigation related to our natural gas sales and firm transportation agreements in "Item 3. Legal proceedings". Inaddition, we are in default under a firm transportation contract with Regency Intrastate Gas LLC ("Regency") since we failed to remit payment during 2017.As a result, Regency is entitled to exercise certain rights and remedies, including the acceleration of the remaining charges under the agreement. As ofDecember 31, 2017, the unpaid amounts and remaining charges under this agreement were $67.3 million.We have an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certaingathering systems over a five-year period ending on November 30, 2018. If there is a shortfall to the minimum volume commitment in any year, then we areseverally responsible with a joint venture partner to pay fixed amounts of money to the gatherer regardless of quantities actually produced in to the systems.For the twelve months ended November 30, 2017, our net share of the shortfall was $23.1 million, which had not been paid prior to the commencement of theChapter 11 Cases.In addition, we have sales and marketing agreements in North Louisiana whereby we are required to deliver a minimum amount of natural gas. Thesecontracts include a natural gas sales contract with a subsidiary of Shell that is currently in litigation. See further discussion of the litigation in "Item 3. Legalproceedings".On January 18, 2018, the Company and the Filing Subsidiaries filed motions to reject certain executory contracts as permitted under the BankruptcyCode. The contracts include the following:•Firm transportation agreements with Acadian, which required us to transport 325,000 Mmbtu per day on the Acadian Gas Pipeline System or payreservation charges through October, 31, 2025;•Natural gas sales agreements with Enterprise, which required us to sell 75,000 Mmbtu per day of natural gas to Enterprise or incur certain coststhrough October 31, 2025;•Firm transportation agreements with Regency, which required us to either transport 237,500 Mmbtu per day of natural gas or pay reservationcharges through January 31, 2020;36Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.•Marketing agreement with Chesapeake, which required us to allow Chesapeake to purchase natural gas for certain wells in North Louisianathrough 2021; and•Natural gas sales agreements with Shell, which required us to sell 100,000 Mmbtu per day of natural gas to Shell or incur certain costs throughNovember 30, 2020.On March 7, 2018, the Court approved the rejection of the aforementioned executory contracts with Regency, Chesapeake and Shell. The hearing toconsider the motion to reject the Enterprise and Acadian contracts is scheduled for March 29, 2018. On March 1, 2018, the Company and the FilingSubsidiaries filed a motion to reject an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and NorthLouisiana to certain gathering systems through November 30, 2018. See further discussion of the future minimum obligations under these contracts as ofDecember 31, 2017 in "Note 8. Commitments and contingencies" and the motions to reject these contracts in "Note 17. Subsequent events" in the Notes toour Consolidated Financial Statements.If we are not able to reject the remainder of these contracts, it could adversely affect our business, financial condition and results of operations.There are risks associated with our drilling activity that could impact our results of operations and financial condition. Our ability to develop properties innew or emerging formations may be subject to more uncertainties than drilling in areas that are more developed or have a longer history of establishedproduction.Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We mustincur significant expenditures to identify and acquire properties and to drill and complete wells. Additionally, seismic and other technology does not allowus to know conclusively prior to drilling a well that oil or natural gas is present or economically producible. The costs of drilling and completing wells areoften uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions,pressure or irregularities in formations, equipment failures or accidents, weather conditions and shortages or delays in the delivery of equipment. We haveexperienced some delays in contracting for drilling rigs and in obtaining fracture stimulation crews and materials. Also, we may experience issues with theavailability of water and sand used in our drilling and hydraulic fracturing activities. All of these risks could adversely affect our results of operations andfinancial condition.The results of our drilling in new or emerging formations, including our properties in shale formations, are more uncertain initially than drilling resultsin areas that are developed, have established production or where we have a longer history of operation. Because new or emerging formations have limited orno production history, we are less able to use past drilling results in those areas to help predict future drilling results. Our experience with horizontal drillingin these areas to date, as well as the industry’s drilling and production history, while growing, is limited. The ultimate success of these drilling andcompletion techniques will be better evaluated over time as more wells are drilled and production profiles are better established. We have implementedseveral initiatives to manage our base production and minimize the decline from our shale properties. If these initiatives are not successful and we arerequired to incur significant expenditures to manage our base production, this could negatively impact our production and cash flows from operations.If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, and/ornatural gas and oil prices decline, our investment in these areas may not be as attractive as we anticipate and we could incur material impairments ofundeveloped properties and the value of our undeveloped acreage could decline in the future, which could have a material adverse effect on our business andresults of operations.Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on theacreage.Leases on oil and natural gas properties typically have a term after which they expire unless, prior to expiration, a well is drilled and production ofhydrocarbons in paying quantities is established. If our leases expire and we are unable to renew the leases, we will lose our right to develop the relatedproperties. While we seek to actively manage our leasehold inventory through drilling wells to hold the leasehold acreage that we believe is material to ouroperations, our drilling plans for these areas are subject to change.37Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.We conduct a substantial portion of our operations through joint interest and joint venture arrangements. Material disagreements with our partners couldhave a material adverse effect on the success of these operations, our financial condition and our results of operations. Furthermore, the actions taken byour partners could prevent or alter our development plans.We conduct a substantial portion of our operations through joint interest and joint venture arrangements with third parties. In many instances, wedepend on these third parties for elements of these arrangements, such as payments of substantial development and other costs. The performance of these thirdparty obligations or the ability of third parties to meet their obligations under these arrangements is outside our control. If these parties do not meet or satisfytheir obligations under these arrangements, the performance and success of these arrangements, and their value to us, may be adversely affected. If our currentor future joint interest or joint venture partners are unable to meet their obligations, we may be forced to undertake the obligations ourselves and/or incuradditional expenses in order to have some other party perform such obligations. In such cases we may also be required to enforce our rights, which may causedisputes among our partners and us. If any of these events occur, they may adversely impact us, our financial performance and results of operations.Such arrangements may involve risks not otherwise present when exploring and developing properties directly, including, for example:•our partners may share certain approval rights over major decisions;•the possibility that our partners might become insolvent or bankrupt, leaving us liable for their shares of joint interest or joint venture liabilities;•the possibility that we may incur liabilities as a result of an action taken by our partners;•partners may be in a position to take action contrary to our instructions or requests or contrary to our policies or objectives;•disputes between us and our partners may result in litigation or arbitration that would increase our expenses, delay or terminate projects andprevent our officers and directors from focusing their time and effort on our business; and•that under certain joint venture arrangements, neither joint venture partner may have the power to control the venture and an impasse could bereached that might have a negative influence on our investment in the joint venture.The failure to resolve disagreements with our partners could adversely affect our ability to transact the business that is the subject of such arrangement,which would in turn negatively affect our financial condition and results of operations. We are currently in litigation with a subsidiary of Shell related totheir failure to remit payment for natural gas sales in the East Texas and North Louisiana regions. The outcome of the litigation could impact our jointventure with Shell in the East Texas and North Louisiana regions. See further discussion related to this litigation in "Item 3. Legal proceedings". Furthermore,on January 26, 2018, we filed a motion to authorize the entry into a settlement agreement with Shell to resolve arbitration regarding our right to participate inan area of mutual interest in the Appalachia region. Under the terms of the settlement agreement, our joint venture with Shell in the Appalachia region wouldbe terminated. The Court approved this settlement agreement on February 22, 2018, and the settlement agreement closed on February 27, 2018. See furtherdiscussion related to the settlement agreement in "Note 17. Subsequent events" in the Notes to our Consolidated Financial Statements.The owners of working interests may not consent to the development of certain properties that we operate, which may require us to assume their shareof the working interest during the development and a period after the well is on production. This may require us to expend additional capital that was notanticipated as part of our development plans and assume additional risks associated with the development and future performance of the properties. Theowners of working interests in certain properties that we operate may also hold rights within the respective operating agreements that could prevent us fromperforming additional development activities on the properties such as recompletions and other workovers without their consent.We may be unable to acquire or develop additional reserves, which would reduce our revenues and access to capital.Our success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are profitable to produce. Factors that mayhinder our ability to acquire or develop additional oil and natural gas reserves include competition, access to capital, prevailing oil and natural gas pricesand the number and attractiveness of properties for sale. If we are unable to conduct successful development activities or acquire properties containingProved Reserves, our total Proved Reserves will generally decline as a result of production. Also, our production will generally decline. We may be unable tolocate additional reserves, drill economically productive wells or acquire properties containing Proved Reserves.38Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Acquisitions, development drilling and exploratory drilling are the main methods of replacing reserves. However, development and exploratorydrilling operations may not result in any increases in reserves for various reasons. Our future oil and natural gas production depends on our success in findingor acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our level of production and cash flows will be adverselyaffected. Throughout 2016 and 2017 we reduced our development activities and suspended drilling in certain regions, which caused our production todecline and negatively impacted our ability to replace our reserves, which in turn negatively impacted our operating results.We may not correctly evaluate reserve data or the exploitation potential of properties as we engage in our acquisition, exploration, development andexploitation activities.Our future success will depend on the success of our acquisition, exploration, development and exploitation activities. Our decisions to purchase,explore, develop or otherwise exploit properties or prospects will depend in part on the evaluation of data obtained from production reports and engineeringstudies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to variousinterpretations. These decisions could significantly reduce our ability to generate cash needed to service our debt and fund our capital program and otherworking capital requirements.Our estimates of oil and natural gas reserves involve inherent uncertainty, which could materially affect the quantity and value of our reported reserves,our financial condition and the value of our common shares.Numerous uncertainties are inherent in estimating quantities of Proved Reserves, including many factors beyond our control. This Annual Report onForm 10-K contains estimates of our Proved Reserves and the PV-10 and Standardized Measure of our Proved Reserves. These estimates are based uponreports of our independent petroleum engineers. These reports rely upon various assumptions, including assumptions required by the SEC as to oil andnatural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. These estimates should not be construed as thecurrent market value of our estimated Proved Reserves.The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of availablegeological, engineering and economic data for each reservoir. As a result, the estimates are inherently imprecise evaluations of reserve quantities and futurenet revenue and such estimates prepared by different engineers or by the same engineers at different times, may vary substantially.Our actual future production, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reservesmay vary substantially from those we have assumed in the estimates. Any significant variance in our assumptions could materially affect the quantity andvalue of reserves, the amount of PV-10 and Standardized Measure described in this Annual Report on Form 10-K, and our financial condition. In addition,our reserves, the amount of PV-10 and Standardized Measure may be revised downward or upward, based upon production history, results of futureexploitation and development activities, prevailing oil and natural gas prices, decisions and assumptions made by engineers and other factors. A materialdecline in prices paid for our production can adversely impact the estimated volumes and values of our reserves. Similarly, a decline in market prices for oilor natural gas may adversely affect our PV-10 and Standardized Measure. Any of these negative effects on our reserves or PV-10 and Standardized Measuremay negatively affect the value of our common shares.Impairments of our asset values could have a substantial negative effect on our results of operations and net worth.We follow the full cost method of accounting for our oil and natural gas properties. Depending upon oil and natural gas prices in the future, and at theend of each quarterly and annual period when we are required to test the carrying value of our assets using full cost accounting rules, we may be required torecord an impairment to the value of our oil and natural gas properties if the present value of the after-tax future cash flows from our oil and natural gasproperties falls below the net book value of these properties. We have in the past experienced, and may experience in the future, ceiling test impairments withrespect to our oil and natural gas properties. As discussed above, we are also currently in Chapter 11 proceedings and, upon the approval of a Chapter 11plan, may be required to apply fresh-start accounting principles that may cause us to experience additional impairments. See “Item 1A. Risk Factors - As aresult of the Chapter 11 cases, our historical financial information may be volatile and not be indicative of our future financial performance” for additionalinformation.Our evaluation of impairment is based upon estimates of Proved Reserves. The value of our Proved Reserves may be lowered in future periods as aresult of a decline in prices of oil and natural gas, a downward revision of our oil and natural gas reserves or other factors. As a result, our evaluation ofimpairment for future periods is subject to uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production andin the timing of development39Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.Because several of these factors are beyond our control, we cannot accurately predict or control the amount of ceiling test impairments in future periods.Future ceiling test impairments could negatively affect our results of operations and net worth.We did not recognize any impairments to our proved oil and natural gas properties for the year ended December 31, 2017. For the years endedDecember 31, 2016 and 2015, we recognized impairments of $160.8 million and $1.2 billion to our proved oil and natural gas properties. We may haveadditional impairments of our oil and natural gas properties in future periods if the cost of our unamortized proved oil and natural gas properties exceeds thelimitation under the full cost method of accounting. The possibility and amount of any future impairment is difficult to predict, and will depend, in part,upon future oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs.We also test goodwill for impairment annually or when circumstances indicate that an impairment may exist. If the book value of our reporting unitexceeds the estimated fair value of the reporting unit, an impairment charge will occur, which would negatively impact our results of operations and networth. As a result of our testing of goodwill for impairment, we did not record an impairment charge for the years ended December 31, 2017, 2016 and 2015.We are exposed to operating hazards and uninsured risks that could adversely impact our results of operations and cash flow.Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:•fires, explosions and blowouts;•pipe failures;•abnormally pressured formations; and•environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment(including groundwater contamination).We have in the past experienced some of these events during our drilling, production and midstream operations. These events may result in substantiallosses to us from:•injury or loss of life;•severe damage to or destruction of property, natural resources and equipment;•pollution or other environmental damage;•environmental clean-up responsibilities;•regulatory investigation;•penalties and suspension of operations; or•attorneys’ fees and other expenses incurred in the prosecution or defense of litigation.As is customary in our industry, we maintain insurance against some, but not all, of these risks. Our insurance may not be adequate to cover thesepotential losses or liabilities. Furthermore, insurance coverage may not continue to be available at commercially acceptable premium levels or at all. Due tocost considerations, from time to time we have declined to obtain coverage for certain drilling activities. We do not carry business interruption insurance.Losses and liabilities arising from uninsured or under-insured events could require us to make large unbudgeted cash expenditures that could adverselyimpact our results of operations and cash flow.We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting ouroperations.Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations. In order to conduct ouroperations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal,state and local governmental authorities. We may incur substantial costs in order to comply with these existing laws and regulations. In addition, our costs ofcompliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Ourbusiness is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction overvarious aspects of the exploration for, production and sale of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted andenforced, could have a material adverse effect on our business, financial condition and results of operations. For additional information, see “Item 1. Business- Applicable Laws and Regulations".40Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Our business exposes us to liability and extensive regulation on environmental matters, which could result in substantial expenditures and couldnegatively impact production.Our operations are subject to numerous complex U.S. federal, state and local laws and regulations relating to the protection of the environment,including those governing the discharge of materials into the water and air, the generation, management and disposal of hazardous substances and wastes andthe clean-up of contaminated sites. Laws, rules and regulations protecting the environment have changed frequently and the changes often includeincreasingly stringent requirements.In general, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmentalauthorities. For example, the EPA has identified environmental compliance by the energy extraction section as one of its enforcement initiatives for fiscalyears 2017 - 2019. This initiative was identified during the prior administration and it is unclear whether the new administration will continue with theongoing initiatives.Compliance with environmental laws and regulations often increases our cost of doing business and, in turn, decreases our profitability. Failure tocomply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the incurrence of investigatory orremedial obligations as well as associated natural resource damages, or the issuance of injunctive relief. Any changes that result in more stringent or costlywaste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and mayotherwise have a material adverse effect on our earnings, results of operations, competitive position or financial condition. Changes to the requirements fordrilling, completing, operating, and abandoning wells and related facilities could have similar adverse effects on us.In addition, we could incur substantial expenditures complying with environmental laws and regulations, including future environmental laws andregulations which may be more stringent than those currently in effect. For example, the regulation of GHG emissions by the EPA or by various states in theareas in which we conduct business could have an adverse effect on our operations and demand for our oil and natural gas production. Moreover, the EPA hasshown a general increased scrutiny on the oil and gas industry through its regulations under the CAA, SDWA, RCRA, TSCA and CWA.The environmental laws and regulations to which we are subject may, among other things:•require us to apply for and receive a permit before drilling commences or certain associated facilities are developed;•restrict the types, quantities and concentrations of substances that can be released into the environment in connection with drilling, hydraulicfracturing, and production activities;•limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other “waters of the United States,” threatened andendangered species habitats and other protected areas;•require remedial measures to mitigate pollution from current or former operations, such as cleaning up spills, dismantling abandoned facilities, pitclosure or plugging abandoned wells;•require additional control and monitoring devices on equipment; and•impose substantial liabilities for pollution resulting from our operations.Our operations may be impacted by recent or changing regulatory standards. For example, the EPA issued effluent limitation guidelines limiting ourability to dispose of waste water from hydraulic fracturing activities into publicly owned wastewater treatment systems. The EPA and state regulators are alsoreviewing the practices for the disposal of solid waste in surface impoundments from exploration and production facilities under Subtitle D of RCRA andmay continue to refine those requirements. The EPA and state regulators are also expanding National Pollutant Discharge Elimination System permitting forstorm water discharges at drilling sites.Changes in regulation can also occur at a state or local level. For example, the State of Pennsylvania Department of Environmental Protection isupdating oil and gas regulations which include more stringent permitting requirements, waste handling disposal and water restoration requirements. Somelocalities, for example in Texas, are enacting water usage restrictions that may impact oil and gas exploration. In addition, some states have considered, andnotably California has adopted, a state specific GHG regulatory program that may limit GHG emissions or may require costs in association with the control ofGHG emissions.41Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.The implementation of climate change regulations could result in increased operating costs and reduced demand for our oil and natural gas production.GHG regulations could require us to incur increased operating costs and could have an adverse effect on demand for our oil and natural gasproduction.In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions.Although the U.S. Supreme Court struck down GHG permitting requirements for GHG as a stand-alone pollutant, it upheld the EPA’s authority to controlGHG emissions when a source has to secure a major source permit to control the emissions of other criteria pollutants. These permitting provisions, to theextent applicable to our operations, could require us to implement emission controls or other measures to reduce GHG emissions and we could incuradditional costs to satisfy those requirements. Additionally, the EPA established GHG reporting requirements for a broad range of sources, including in thepetroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although this ruledoes not limit the amount of GHGs that can be emitted, it requires us to incur costs to monitor record and report GHG emissions associated with ouroperations.As part of a move to reduce GHG emissions, the EPA has issued new rules limiting methane emissions from new or modified oil and gas sources. Therules amend the air emissions rules for the oil and natural gas sources and natural gas processing and transmission sources to include new standards formethane. Simultaneously with the methane rules, the EPA adopted new rules governing the aggregating of multiple surface sites into a single-source of airquality permitting purposes. The grouping together of sources may cause a group of sources to be treated as a “major source” and face enhanced regulationunder federal environmental laws, including the CAA.Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operatingrestrictions or delays.Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Mosthydraulic fracturing (other than hydraulic fracturing using diesel) is exempted from regulation under the SDWA. Congress has considered legislation toamend the federal SDWA to remove the exemption from regulation and permitting that is applicable to hydraulic fracturing operations and require reportingand disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Many states have adopted or are consideringlegislation regulating hydraulic fracturing, including the disclosure of chemicals used in the process. Such bills or similar legislation, if adopted, couldincrease the possibility of litigation and establish an additional level of regulation that could lead to operational delays or increased operating costs andcould result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance. At the state andlocal levels, some jurisdictions have adopted, and others are considering adopting, requirements that could impose more stringent permitting, publicdisclosure or well construction requirements on hydraulic fracturing activities, as well as bans on hydraulic fracturing activities. In the event that new or morestringent state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we have properties, we could incur potentiallysignificant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or productionactivities, and perhaps even be precluded from drilling wells.In addition, the EPA has asserted federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection ControlProgram (“UIC”) and has issued guidance regarding its authority over the permitting of these activities. Additionally, in December 2016, the EPA released itsfinal report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulicfracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low wateravailability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequatemechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surfacewaters; and disposal or storage of fracturing wastewater in unlined pits. If this assessment results in additional regulatory scrutiny, it could make it difficult toperform hydraulic fracturing and increase our costs of compliance and doing business. Consequently, these studies and initiatives could spur furtherlegislative or regulatory action regarding hydraulic fracturing or similar production operations.Further, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventionaloil and natural gas extraction facilities to publicly owned wastewater treatment plants.These new initiatives related to hydraulic fracturing may increase our cost of disposal and impact our business operations and could cause ourhydraulic fracturing activities to become subject to additional permit requirements or operations42Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.restrictions which could lead to permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could reduce the amount of oil andnatural gas that we ultimately are able to produce.The EPA has adopted rules to limit air emissions from oil and gas operations, subjecting oil and natural gas production, processing, transmission andstorage operations to regulation under the NSPS and NESHAPS programs under the CAA. The EPA rules include NSPS standards for completions ofhydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sentto the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using greencompletions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale,which can be done through the use of green completions. The standards are applicable to newly fractured wells and also existing wells that are refractured.Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storagetanks, natural gas processing plants and certain other equipment. The implementation of these new requirements may result in increased operating andcompliance costs, increased regulatory burdens and delays in our operations. There may also be further refinement to existing NSPS standards for VOCs asdata is gathered about the implementation of those requirements.We operate in a litigious environment.Any constituent could bring suit regarding our existing or planned operations or allege a violation of an existing contract. Any such action coulddelay when planned operations can actually commence or could cause a halt to existing production until such alleged violations are resolved by the courts.Not only could we incur significant legal and support expenses in defending our rights, but halting existing production or delaying planned operations couldimpact our future operations and financial condition. In addition, we are defendants in numerous cases involving claims by landowners for surface orsubsurface damages arising from our operations and for claims by unleased mineral owners and royalty owners for unpaid or underpaid revenues customary inour business. We incur costs in defending these claims and from time to time must pay damages or other amounts due. Such legal disputes can also distractmanagement and other personnel from their primary responsibilities. For additional information on our significant litigation matters, see “Item 3. LegalProceedings" and "Note 8. Commitments and contingencies” in the Notes to our Consolidated Financial Statements.Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions.As an oil and natural gas production company, we face various security threats, including cybersecurity threats to gain unauthorized access tosensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure orthird party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize various procedures andcontrols to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient inpreventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, criticalinfrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results ofoperations or cash flows. Cybersecurity attacks in particular are evolving and include but are not limited to, malicious software, attempts to gainunauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential orotherwise protected information and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss ofbusiness or potential liability.There are inherent limitations in all internal control over financial reporting, and misstatements due to error or fraud may occur and not be detected.While we have taken actions designed to address compliance with the internal control, disclosure control and other requirements of the Sarbanes-Oxley Act of 2002, as amended, and the rules and regulations promulgated by the SEC implementing these requirements, there are inherent limitations in ourability to control all circumstances. Our management, including our chief financial officer and chief accounting officer, do not expect that our internalcontrols and disclosure controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide onlyreasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that thereare resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation ofcontrols can provide absolute assurance that all control issues and instances of fraud, if any, in our company have been detected. These inherent limitationsinclude the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controlscan be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of anysystem of controls also is based in part upon certain assumptions about the likelihood of future43Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control maybe inadequate because of changes in conditions, such as growth of our company or increased transaction volume, or the degree of compliance with thepolicies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur andnot be detected.The Consolidated Financial Statements included herein contain disclosures that express substantial doubt about our ability to continue as a goingconcern, indicating the possibility that we may not be able to operate in the future.The Consolidated Financial Statements included herein have been prepared on a going concern basis, which contemplates the realization of assets andthe satisfaction of liabilities and other commitments in the normal course of business. The Consolidated Financial Statements do not reflect any adjustmentsthat might result from the outcome of our Chapter 11 proceedings. Our level of indebtedness has adversely impacted and is continuing to adversely impactour financial condition. The outcome of our Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors outside of ourcontrol, including actions of the Court and our creditors. The significant risks and uncertainties related to our liquidity and Chapter 11 proceedings describedabove raise substantial doubt about our ability to continue as a going concern.See further discussion regarding our ability to continue as a going concern as part of "Note 1. Organization and basis of presentation" in the Notes toour Consolidated Financial Statements.Risks Relating to Our Common SharesOur common shares are no longer listed on a national securities exchange and are quoted only in over-the-counter markets, which may have a negativeimpact on our share price, volatility and Liquidity.On December 22, 2017, the NYSE suspended trading in our common shares and commenced proceedings to delist our common shares due to ourfailure to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million pursuant to Section 802.01B ofthe NYSE Listed Company Manual.On December 27, 2017, our common shares began trading over the counter on the OTC Pink Marketplace under the ticker symbol “XCOO.” Ourcommon shares continue to trade under that symbol with the added designation of “Q” to symbolize that we are currently in bankruptcy proceedings.The delisting of our common shares from the NYSE and commencement of trading on the OTC Pink Marketplace has resulted and may continue toresult in a reduction in some or all of the following, each of which could have a material adverse effect on our shareholders:•the liquidity of our common shares;•the market price of shares of our common shares;•our ability to obtain financing for the continuation of our operations;•the number of institutional and other investors that will consider investing in shares of our common shares;•the number of market makers in our common shares;•the availability of information concerning the trading prices and volume of our common shares; and•the number of broker-dealers willing to execute trades in our common shares.Although our common shares have been delisted from the NYSE, we are required to continue filing periodic reports with the SEC unless and until wetake action to deregister our common shares under Section 12(g) of the Exchange Act and suspend our reporting obligations under Section 15(d) of theExchange Act.Our common share price may fluctuate significantly.Our common shares currently trade on the OTC Pink Marketplace but an active trading market for our common shares may not be sustained. Themarket price of our common shares could fluctuate significantly as a result of:•bankruptcy proceedings and the outcome of the Chapter 11 Cases;•dilutive issuances of our common shares;•announcements relating to our business or the business of our competitors;•changes in expectations as to our future financial performance or changes in financial estimates of public market analysis;•actual or anticipated quarterly variations in our operating results;44Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.•conditions generally affecting the oil and natural gas industry;•the success of our operating strategy; and•the operating and share price performance of other comparable companies.Many of these factors are beyond our control and we cannot predict their potential effects on the price of our common shares. In addition, the stockmarkets in general can experience considerable price and volume fluctuations. See further discussion of the impact of the Chapter 11 Cases on our commonshares in Item "1A. Risk Factors - We believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11proceedings".Item 1B.Unresolved Staff CommentsNot applicable.Item 2.PropertiesCorporate officesWe lease office space in Dallas, Texas. We also have small offices for technical and field operations in Texas, Louisiana and Pennsylvania. The tablebelow summarizes our material corporate leases.Location Approximate square footage Approximate remaining monthlypayment ExpirationDallas, Texas (1) 155,000 $251,000 May 31, 2025(1)The office lease in Dallas, Texas contains a right on our behalf to terminate the lease agreement early on June 30, 2020 or June 30, 2022.OtherWe have described our oil and natural gas properties, oil and natural gas reserves, acreage, wells, production and drilling activity in “Item 1. Business”of this Annual Report on Form 10-K.Item 3.Legal ProceedingsBankruptcy proceedings under Chapter 11On January 15, 2018, the Company and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. See "Note17. Subsequent events" in the Notes to our Consolidated Financial Statements for additional information.Enterprise and Acadian contract litigationDuring the third quarter of 2016, we terminated our sales and transportation contracts with Enterprise and Acadian, respectively. Enterprise andAcadian are part of the corporate family of Enterprise Products Partners L.P. (“EPD”). Under the parties’ sales and transportation agreements, Enterprise owedus for July 2016 natural gas sales, and we owed Acadian for July 2016 transportation fees. The amount owed to us by Enterprise exceeded the amount owedby us to Acadian. We notified Enterprise in writing of its failure to pay and gave Enterprise opportunity to cure. When Enterprise failed to cure, we gavewritten notice to Enterprise and Acadian that we were terminating the sales and transportation agreements. Enterprise subsequently filed an amended petitionat Enterprise Products Operating LLC and Acadian Gas Pipeline System v. EXCO Operating Company, LP, EXCO Partners OLP GP, LLC, Raider Marketing,LP, and Raider Marketing GP, LLC No. 2016-60848 157th Judicial District, Harris County, Texas. The amended petition alleges that we could not terminatethe parties’ agreements despite Enterprise's uncured payment default under the gas sales agreement, and further alleged that we were in breach of the firmtransportation agreements. On October 17, 2016, we filed a counterclaim asserting that Enterprise was the breaching party because it improperly withheldpayment for natural gas we delivered and the amounts owed by Enterprise exceeded the amounts owed by us to Acadian. We are also seeking a declarationthat we properly terminated the contracts with Enterprise and Acadian, as well as payment of the amounts owed to us under the agreements. EPDsubsequently joined two of our officers, Harold Hickey and Steve Estes, asserting breach of fiduciary duty claims and thereafter joined Bluescape assertingtortious interference with an existing contract. We have filed a summary judgment motion as to the claims against us and our45Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.officers, and the motion is pending before the court. If we prevail on the summary judgment motion it could be case dispositive. This case was anticipated togo to trial in the second or third quarter of 2018; however, the case is stayed due to our Chapter 11 filings. EPD has filed a motion to lift the stay.Chesapeake natural gas sales contract litigationOn June 6, 2017, we filed a petition, application for temporary restraining order and temporary injunction against Chesapeake Energy Marketing, LLC("CEML") in Dallas County, Texas, Case No. DC-17-06672, in the 14th District Court of Dallas County, Texas, for allegedly terminating a long-term salescontract with an expiration of June 30, 2032, between Chesapeake and Raider Marketing, LP ("Raider"). We are asserting breach of contract, tortiousinterference with existing contract, tortious interference with prospective business relations, and declaratory relief that the contract is still in full force andeffect. On June 7, 2017, Chesapeake filed to remove the lawsuit to the United States District Court Northern District of Texas. We subsequently joinedChesapeake Energy Corporation ("CEC"). CEC has filed a motion to dismiss for lack of personal jurisdiction, and the motion remains pending. See furtherdiscussion in "Note 3. Acquisitions, divestitures and other significant events" in the Notes to our Consolidated Financial Statements. Shell natural gas sales contract litigationWe are plaintiffs in an adversary proceeding pending in the United States Bankruptcy Court for the Southern District of Texas, Houston Division underCase No. 18-30155. This lawsuit was originally filed in Harris County District Court on December 26, 2017. We filed a notice of non-suit without prejudiceon January 26, 2018 in order to bring the claim as an adversary proceeding in the Chapter 11 reorganization. EXCO initiated this adversary proceedingagainst Shell Energy North America (US) LP ("Shell Energy"), a subsidiary of Shell, on January 26, 2018. We brought suit as a result of Shell Energy’simproper withholding of approximately $33.4 million in revenue, which EXCO is owed under the parties’ Base Contract for Sale and Purchase of Natural Gasexecuted in August of 2009. This unpaid revenue is due to EXCO for the natural gas EXCO delivered to Shell Energy for the months of November andDecember 2017.Item 4.Mine Safety DisclosuresNot applicable.PART IIItem 5.Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity SecuritiesMarket information for our common sharesOur common shares have historically been traded on the NYSE. On December 22, 2017, the NYSE suspended the trading of our common shares andcommenced proceedings to delist our common shares due to our failure to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million. As a result, on December 27, 2017, our common shares commenced trading on the OTC Pink Marketplace under thesymbol “XCOO”. Subsequent to our filing voluntary petitions for relief under Chapter 11 on January 15, 2018, our common shares are quoted over-the-counter under the symbol "XCOOQ".46Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.The following table sets forth for the periods indicated, the highest and lowest sales price for our common shares, as reported on the NYSE for theperiods through December 22, 2017, and the quarterly high and low bid quotations for our common shares as reported over-the-counter for the periodbeginning December 27, 2017: Price per share High Low2017 First Quarter $14.70 $7.05Second Quarter 9.90 2.65Third Quarter 2.81 1.00Fourth Quarter 1.72 0.19 2016 First Quarter $29.10 $10.50Second Quarter 28.65 7.65Third Quarter 21.30 13.50Fourth Quarter 18.90 12.75Our shareholdersAccording to our transfer agent, Continental Stock Transfer & Trust Company, there were 132 holders of record of our common shares on December 31,2017 (including nominee holders such as banks and brokerage firms who hold shares for beneficial holders and holders of restricted shares).Our dividend policyWe have not paid any dividends on our common shares since 2014 and we do not anticipate paying any dividends on our common shares in theforeseeable future. The agreements governing our indebtedness contain covenants that generally limit our ability to pay dividends. In addition, we arecurrently prohibited from paying cash dividends on our common shares under the Bankruptcy Code, as well as under Texas law because we have negativeshareholders’ equity. Any future declaration of dividends, as well as the establishment of record and payment dates, will depend on, among other things, ourearnings, capital requirements, financial condition, prospects and other factors our Board of Directors may deem relevant.Issuer repurchases of common sharesThe following table details our repurchases of common shares for the three months ended December 31, 2017:Period Total Number of SharesPurchased Average Price Paid PerShare Total Number of SharesPurchased as Part ofPublicly AnnouncedPlans or Programs Maximum Approximate Dollar Valueof Shares that May Yet Be PurchasedUnder the Plans or Programs (inmillions) (1)October 1 - October 31 — $— — $192.5November 1 - November 30 — — — 192.5December 1 - December 31 — — — 192.5 Total — — — (1)On July 19, 2010, we announced a $200.0 million share repurchase program.47Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Item 6.Selected Financial DataThe following table presents our selected historical financial and operating data. This financial data should be read in conjunction with “Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations,” our Consolidated Financial Statements, the Notes to ourConsolidated Financial Statements and the other financial information included in this Annual Report on Form 10-K. This information does not replace theConsolidated Financial Statements. Certain reclassifications have been made to prior period information to conform to current period presentation.Selected consolidated financial and operating data Year Ended December 31,(in thousands, except per share amounts) 2017 2016 2015 2014 2013Statement of operations data (1): Total revenues $283,646 $271,001 $355,700 $695,917 $663,090Operating income (loss) (2) (40,556) (220,949) (1,339,875) 126,875 179,221Net income (loss) (3)(4)(5) $24,362 $(225,258) $(1,192,381) $120,669 $22,204Basic net income (loss) per share $1.14 $(12.09) $(65.37) $6.75 $1.55Diluted net income (loss) per share $1.14 $(12.09) $(65.37) $6.74 $1.44Cash dividends declared per share $— $— $— $2.25 $3.00Weighted average common shares and common share equivalentsoutstanding: Basic 21,288 18,630 18,241 17,884 14,334Diluted 21,288 18,630 18,241 17,892 15,394Statement of cash flow data: Net cash provided by (used in): Operating activities $54,411 $(414) $134,027 $362,093 $350,634Investing activities (182,551) (55,009) (300,833) (221,588) (252,478)Financing activities 158,669 52,244 132,748 (144,683) (93,317)Balance sheet data: Current assets $167,830 $110,617 $149,801 $330,766 $305,854Total assets 840,347 661,414 954,126 2,304,942 2,399,836Current liabilities (6) 1,666,970 258,363 252,919 329,436 349,170Long-term debt (6) — 1,258,538 1,320,279 1,430,516 1,850,120Shareholders' equity (846,199) (871,906) (662,323) 510,004 147,905Total liabilities and shareholders' equity 840,347 661,414 954,126 2,304,942 2,399,836(1)We have completed numerous acquisitions and dispositions which impact the comparability of the selected financial data between periods.(2)Operating income (loss) during 2017 was impacted by the acceleration of the remaining $56.4 million in costs under a firm transportation agreement. See "Note 8.Commitments and contingencies" in the Notes to our Consolidated Financial Statements for additional information. Operating income (loss) loss during 2016 wasimpacted by the impairment of oil and natural gas properties charge of $160.8 million and the settlement of the litigation with a joint venture partner. See "Note 3.Acquisitions, divestitures and other significant events" in the Notes to our Consolidated Financial Statements for additional information regarding the litigation with ourjoint venture partner. Operating income (loss) during 2015 was impacted by the impairment of oil and natural gas properties charge of $1.2 billion. Operating income(loss) during 2013 was impacted by a gain recognized on the contribution of properties to Compass Production Partners, L.P. ("Compass").(3)In March 2017, we issued warrants to the investors of 1.5 Lien Notes and to certain exchanging holders of the Second Lien Term Loans (collectively referred to as the"2017 Warrants" as defined in "Note 4. Derivative financial instruments" in the Notes to our Consolidated Financial Statements). We record the 2017 Warrants as non-current liabilities at fair value, with the increase or decrease in fair value being recognized in earnings. As a result of the change in the fair value of the 2017 Warrants, werecorded a gain of $159.2 million on the revaluation of the warrants during the year ended December 31, 2017.(4)During 2016, we recognized a net gain on extinguishment of debt $119.5 million due to repurchases of a portion of the 2018 Notes and 2022 Notes. During 2015, werecognized a gain on restructuring and extinguishment of debt as a result of repurchasing a portion of our 2018 Notes and 2022 Notes in exchange for the holders of suchnotes agreeing to act as lenders in connection with48Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.the Exchange Term Loan (as defined in "Note 5. Debt" in the Notes to our Consolidated Financial Statements). In addition, we repurchased a portion of the 2018 Notes inopen market purchases which resulted in a net gain on extinguishment of debt. See "Note 5. Debt" in the Notes to our Consolidated Financial Statements for furtherdiscussion.(5)On November 15, 2013, we sold our equity interest in TGGT Holdings, LLC ("TGGT") to Azure Midstream Holdings LLC ("Azure") in exchange for cash proceedsand an equity interest in Azure. We report our equity interest acquired in Azure using the cost method of accounting.(6)During 2017, we reclassified all of our outstanding indebtedness to a current liability as a result of agreements entered into in anticipation of events of default undercertain debt agreements, as well as any outstanding debt with cross-default provisions, and an event of default under the Second Lien Term Loans. See "Note 5. Debt" inthe Notes to our Consolidated Financial Statements for further discussion.Item 7.Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe following management's discussion and analysis of our financial condition and results of operations should be read in conjunction with ourfinancial statements and the related notes to those statements included elsewhere in this Annual Report on Form 10-K. In addition to historical financialinformation, the following management's discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions.Our results and the timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors,including those discussed under “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K.Overview and historyWe are an independent oil and natural gas company engaged in the exploration, exploitation, acquisition, development and production of onshoreU.S. oil and natural gas properties with a focus on shale resource plays. Our principal operations are conducted in certain key U.S. oil and natural gas areasincluding Texas, Louisiana and the Appalachia region. Our primary strategy focuses on the exploitation and development of our shale resource plays and thepursuit of leasing and acquisition opportunities.Like all oil and natural gas exploration and production companies, we face the challenge of natural production declines. We attempt to offset theimpact of this natural decline by implementing drilling and exploitation projects to identify and develop additional reserves and adding reserves throughleasing and undeveloped acreage acquisition opportunities. Our financial condition has been negatively impacted by the prolonged depressed oil andnatural gas price environment, levels of indebtedness, and gathering, transportation and certain other commercial contracts.Chapter 11 CasesOn January 15, 2018, the Company and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in theUnited States Bankruptcy Court for the Southern District of Texas. The Debtors have filed a motion with the Court seeking joint administration of theirChapter 11 cases under the caption In Re EXCO Resources, Inc., Case No. 18-30155 (MI). The Court has granted all of the first day motions filed by theDebtors that were designed primarily to minimize the impact of the Chapter 11 proceedings on our operations, customers and employees. We will continue tooperate our businesses as “debtors in possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the BankruptcyCode and orders of the Court. We expect to continue our operations without interruption during the pendency of the Chapter 11 proceedings.On January 22, 2018, we closed the DIP Credit Agreement, which includes an initial borrowing base of $250.0 million. The proceeds from the DIPFacilities were used to refinance all obligations outstanding under the EXCO Resources Credit Agreement and will provide additional liquidity to fund ouroperations during the Chapter 11 process. We continue to engage in discussions with our creditors regarding the terms of a financial restructuring plan. Inconjunction with this process, we will explore potential strategic alternatives to maximize value for the benefit of our stakeholders, which may include a saleof certain or substantially all of our assets under Section 363 of the Bankruptcy Code, a plan of reorganization to equitize certain indebtedness as analternative to the sale process, or a combination thereof.For the duration of the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to risks anduncertainties associated with Chapter 11 proceedings described in "Item 1A. Risk Factors”. As a result49Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.of these risks and uncertainties, our assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11proceedings, and the description of our operations, properties and capital plans included in this annual report may not accurately reflect our operations,properties and capital plans following the Chapter 11 proceedings. See further discussion of the Chapter 11 Cases in "Note 17. Subsequent events" in theNotes to our Consolidated Financial Statements.Appalachia JV SettlementOn February 27, 2018, we closed the Appalachia JV Settlement with a subsidiary of Shell to resolve arbitration regarding our right to participate in anarea of mutual interest in the Appalachia region. As a result of the Appalachia JV Settlement, we acquired Shell's interests in the joint venture in Appalachia,an entity that operates the wells in the joint venture in Appalachia and an entity that owns and operates midstream assets in the Appalachia region. As aresult, our production, revenues and expenses in the Appalachia region are expected to increase in the future. Also, our recoveries of general andadministrative expenses related to the joint venture in Appalachia are expected to decrease in the future. See further discussion of this settlement as part of"Note 17. Subsequent events" in the Notes to our Consolidated Financial Statements.Financing transactions and restructuring activities during 2017On March 15, 2017, we closed a series of transactions including the issuance of $300.0 million in aggregate principal amount of 1.5 Lien Notes,exchange of $682.8 million in aggregate principal amount of Second Lien Term Loans for a like amount of 1.75 Lien Term Loans and issuance of warrants topurchase our common shares. The terms of the indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans allowfor interest payments in cash, common shares or additional indebtedness, subject to certain restrictions and limitations. The transaction fees paid to thelenders included a combination of cash and warrants to purchase our common shares. The 1.5 Lien Notes were issued to affiliates of Fairfax, Bluescape andOaktree Capital Management, LP ("Oaktree"), as well as an unaffiliated lender.The proceeds from the 1.5 Lien Notes were primarily utilized to repay the outstanding indebtedness under the EXCO Resources Credit Agreement as ofMarch 2017. In connection with these transactions, the EXCO Resources Credit Agreement was amended to reduce the borrowing base to $150.0 million,permit the issuance of the 1.5 Lien Notes and the exchange of Second Lien Term Loans, and modify certain financial covenants. On June 20, 2017, we paidinterest on the 1.75 Lien Term Loans in common shares, which resulted in the issuance of 2,745,754 common shares. On September 20, 2017, we paid $17.0million and $26.2 million of interest on the 1.5 Lien Notes and 1.75 Lien Term Loans, respectively, through the issuance of additional 1.5 Lien Notes and1.75 Lien Term Loans.On September 7, 2017, we announced that our Board of Directors delegated authority to the independent directors of the Audit Committee to explorestrategic alternatives to strengthen the Company’s balance sheet and maximize the value of the Company, which included, but was not limited to, seeking acomprehensive out-of-court restructuring or reorganization under Chapter 11 of the Bankruptcy Code. At the direction of the Audit Committee, we retainedPJT Partners LP as financial advisors and Alvarez & Marsal North America, LLC as restructuring advisors, and continued to engage Kirkland & Ellis LLP aslegal advisors to assist the Company with the restructuring process. We initiated discussions with certain stakeholders regarding strategic alternatives torestructure our balance sheet. During the third quarter of 2017, the Compensation Committee of the Board of Directors and the Company revised ouremployee compensation programs to retain employees and align the interests of employees with our stakeholders. The revised incentive plans solely consistof cash-based compensation and we have discontinued the grant of share-based compensation to employees until the completion of a restructuring. Seefurther discussion of the revisions to our employee compensation programs in "Note 11. Equity-based and other incentive-based compensation" in the Notesto our Consolidated Financial Statements.During the third quarter of 2017, we borrowed substantially all of our remaining unused commitments under the EXCO Resources Credit Agreement.On September 29, 2017, we obtained a limited waiver from the lenders under the EXCO Resources Credit agreement waiving an event of default as a result ofa failure to comply with certain financial covenants as of September 30, 2017.Due to liquidity constraints and restrictions and limitations on our ability to pay interest in cash, common shares or additional indebtedness, we didnot make our interest payment on the 1.75 Lien Term Loans that was due on December 20, 2017 and the interest payment on the Second Lien Term Loansthat was due on December 26, 2017. In anticipation of certain events of default related to compliance with financial covenants and failure to pay interest oncertain debt instruments, we entered into agreements with certain holders of the indebtedness under our EXCO Resources Credit Agreement, 1.5 Lien Notes,and 1.75 Lien Term Loans to forbear from exercising their rights and remedies as a result of an event of default under such debt instruments until January 15,2018. See further discussion in "Note 5. Debt" in the Notes to our Consolidated Financial Statements.50Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Changes to Board of DirectorsOn September 20, 2017, each of B. James Ford and Samuel A. Mitchell resigned from their respective positions as members of our Board of Directors.At the time of their respective resignations, neither Mr. Ford nor Mr. Mitchell was a member of any committee of the Board. On October 6, 2017, Stephen J.Toy resigned from his position as a member of the Board. At the time of his resignation, Mr. Toy was a member of each of the Audit Committee,Compensation Committee and Nominating and Corporate Governance Committee of the Board. On November 9, 2017, C. John Wilder resigned from hisposition as a member of the Board and as Executive Chairman of the Board. At the time of his resignation, Mr. Wilder was not a member of any committee ofthe Board. In connection with the resignation of Mr. Wilder, we entered into a suspension agreement with Energy Strategic Advisory Services LLC ("ESAS")pursuant to which, among other things: (i) the services and investment agreement with ESAS, dated as of March 31, 2015, was suspended such that, duringthe suspension period and subject to the terms and conditions of the agreement: (a) ESAS is not required to provide any services to us, (b) we are not requiredto make any payments to ESAS with respect to the suspension period and (c) ESAS does not have the right to nominate a member to the Company’s Board ofDirectors; and (ii) the warrants previously issued to ESAS under the services and investment agreement ("ESAS Warrants") were forfeited and canceled and wehave no further obligations under the ESAS Warrants. ESAS is a wholly owned subsidiary of an affiliate of Bluescape, and Mr. Wilder serves as the ExecutiveChairman of Bluescape and indirectly controls ESAS.Reverse share split and NYSE complianceOn June 2, 2017, we filed a certificate of amendment to our Amended and Restated Certificate of Formation to reduce the number of authorizedcommon shares from 780,000,000 to 260,000,000 and effect a 1-for-15 reverse share split. The reverse share split became effective after the market closed onJune 12, 2017. See "Note 1. Organization and basis of presentation" in the Notes to our Consolidated Financial Statements for further discussion.As a result of our failure to maintain certain continued listing standards on the NYSE, our common shares were suspended from trading on the NYSEon December 22, 2017. Our common shares are traded over-the-counter under the symbol "XCOOQ".Termination of South Texas DivestitureOn April 7, 2017, we entered into a purchase and sale agreement with a subsidiary of Venado Oil and Gas, LLC ("Venado") to divest our oil andnatural gas properties and surface acreage in South Texas for a total purchase price of $300.0 million that was subject to closing conditions and adjustmentsbased on an effective date of January 1, 2017.Pursuant to the terms of the agreement, the closing of the transaction was originally anticipated to occur on June 1, 2017 (the “Original ScheduledClosing Date”), unless certain conditions had not been satisfied or waived on or prior to the Original Scheduled Closing Date. The purchase agreementincluded conditions to the closing, including seller's representation and warranty regarding all material contracts being in full force and effect be true as ofthe Original Scheduled Closing Date. As described in "Note 3. Acquisitions, divestitures and other significant events" in the Notes to our ConsolidatedFinancial Statements, the closing conditions were not anticipated to be satisfied or waived by the Original Scheduled Closing Date due to the allegedtermination of a long-term natural gas sales contract by CEML. We are currently in litigation with CEML as a result of their alleged termination of thecontract, see further discussion in "Item 3. Legal proceedings". Therefore, we entered into an amendment to extend the Original Scheduled Closing Date toAugust 15, 2017.The amendment, among other things, provided that the satisfaction of the closing conditions would be deemed satisfied by the reinstatement of thenatural gas sales contract or by entry into a new gathering agreement. Because all closing conditions had not been satisfied or waived by August 15, 2017,EXCO and Venado mutually agreed to terminate the purchase and sale agreement, effective as of August 15, 2017. Following the termination, the purchaseand sale agreement was void and of no further effect.Critical accounting estimatesThe process of preparing financial statements in conformity with GAAP requires us to make estimates and assumptions to determine reported amountsof certain assets, liabilities, revenues, expenses and related disclosures. We have identified the most critical accounting policies used in the preparation of ourConsolidated Financial Statements. We determined the critical policies by considering accounting policies that involve the most complex or subjectivedecisions or assessments. We identified our most critical accounting policies to be those related to our estimates of Proved Reserves, derivative financialinstruments,51Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.business combinations, equity-based compensation, oil and natural gas properties, goodwill, revenue recognition, asset retirement obligations and incometaxes.The following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in our application of GAAP. For amore complete discussion of our accounting policies see "Note 2. Summary of significant accounting policies" in the Notes to our Consolidated FinancialStatements.Estimates of Proved ReservesThe Proved Reserves data included in this Annual Report on Form 10-K was prepared in accordance with SEC guidelines. The accuracy of a reserveestimate is a function of:•the quality and quantity of available data;•the interpretation of this data;•the accuracy of various mandated economic assumptions; and•the technical qualifications, experience and judgment of the persons preparing the estimates. Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different fromthe quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate mayjustify material revisions to the estimate. The assumptions used for our shale properties including reservoir characteristics and performance are subject tofurther refinement as additional production history is accumulated.You should not assume that the present value of future net cash flows represents the current market value of our estimated Proved Reserves. Inaccordance with the SEC's requirements, we based the estimated discounted future net cash flows from Proved Reserves according to the requirements in theSEC's Release No. 33-8995 Modernization of Oil and Gas Reporting. Actual future prices and costs may be materially higher or lower than the prices andcosts used in the preparation of the estimate. Further, the mandated discount rate of 10% may not be an accurate assumption of future interest rates or cost ofcapital.Proved Reserve quantities directly and materially impact depletion expense. If the Proved Reserves decline, then the rate at which we record depletionexpense increases. A decline in the estimate of Proved Reserves may result from lower market prices, making it uneconomical to drill or produce from highercost fields. In addition, a decline in Proved Reserves may impact the outcome of our assessment of our oil and natural gas properties and require animpairment of the carrying value of our oil and natural gas properties.Business combinationsWhen we acquire assets that qualify as a business, we use FASB ASC 805-10, Business Combinations ("ASC 805-10") to record our acquisitions of oiland natural gas properties or entities. ASC 805-10 requires that acquired assets, identifiable intangible assets and liabilities be recorded at their fair value,with any excess purchase price being recognized as goodwill. Application of ASC 805-10 requires significant estimates to be made by management usinginformation available at the time of acquisition. Since these estimates require the use of significant judgment, actual results could vary as the estimates aresubject to changes as new information becomes available.Derivative financial instrumentsWe use derivative financial instruments to manage price fluctuations, protect our investments and achieve a more predictable cash flow. The estimatesof the fair values of our derivative financial instruments require judgment. The fair value of our derivative financial instruments is determined by quotedfutures prices, utilization of the credit-adjusted risk-free rate curves and the implied rates of volatility. We do not designate our derivative financialinstruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respective instruments’ fair value inearnings. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activitiesconsists of non-cash income or expense due to changes in the fair value of our derivative financial instruments.On March 15, 2017, we issued warrants to investors in connection with the issuance of the 1.5 Lien Notes and 1.75 Lien Term Loans in March 2017.The 2017 Warrants are accounted for as derivatives in accordance with FASB ASC 815, Derivatives and Hedging, ("ASC 815"), and required to be classifiedas liabilities due to the types of anti-dilution adjustments.52Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.We record the 2017 Warrants as non-current liabilities at fair value, with the increase or decrease in fair value being recognized in earnings. The liabilityattributable to our common share warrants as of the issuance date and the end of each reporting period was measured using the Black-Scholes model based oninputs including our share price, volatility, expected remaining life and the risk-free rate of return. The implied rates of volatility were determined based onhistorical prices of our common shares over a period consistent with the expected remaining life. The 2017 Warrants will be measured at fair value on arecurring basis until the date of exercise, cancellation or expiration.Equity-based compensationOur equity-based compensation includes share-based compensation to employees which we account for in accordance with FASB ASC 718,Compensation-Stock Compensation ("ASC 718") and equity-based compensation for warrants issued to ESAS which we account for in accordance with FASBASC 505-50, Equity-Based Payments to Non-Employees ("ASC 505-50").ASC 718 requires share-based compensation to employees to be recognized in our Consolidated Statements of Operations based on their estimated fairvalues. Estimating the grant date fair value of our share-based compensation requires management to make assumptions and to apply judgment in estimatingthe fair value. These assumptions and judgments include estimating the volatility of our share price, dividend yields, expected term, forfeiture rates and othercompany-specific inputs. ASC 505-50 requires the warrants to be re-measured each interim reporting period until the completion of the services under theagreement and an adjustment is recorded in our Consolidated Statements of Operations. The fair value of the warrants is dependent on factors such as ourshare price, historical volatility, risk-free rate and performance relative to our peer group.Changes in these assumptions could materially affect the estimate of the fair value. If actual results are not consistent with the assumptions used, theequity-based compensation expense reported in our financial statements may not be representative of the actual economic impact of the equity-basedcompensation.Oil and natural gas propertiesThe accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives: the full costmethod or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitationand development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unprovedproperties, collectively, the full cost pool. Our unproved property costs are not subject to depletion. We review our unproved oil and natural gas propertycosts on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extension or discoveries fromdrilling operations or determination that no Proved Reserves are attributable to such costs. In determining whether such costs should be impaired ortransferred, we evaluate lease expiration dates, recent drilling results, future development plans and current market values. Our undeveloped properties arepredominantly held-by-production, which reduces the risk of impairment as a result of lease expirations.We capitalize interest on the costs related to the acquisition of undeveloped acreage in accordance with FASB ASC 835-20, Capitalization of Interest.When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we ceasecapitalizing interest related to these properties. We capitalize the portion of general and administrative costs, including share-based compensation, which isattributable to our acquisition, exploration, exploitation and development activities.We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unprovedproperties, and all estimated future development costs less estimated salvage value are divided by the total estimated quantities of Proved Reserves. This rateis applied to our total production for the quarter, and the appropriate expense is recorded.Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gainor loss, unless the disposition would significantly alter the amortization rate and/or the relationship between capitalized costs and Proved Reserves.Pursuant to Rule 4-10(c)(4) of Regulation S-X, at the end of each quarterly period, companies that use the full cost method of accounting for their oiland natural gas properties must compute a limitation on capitalized costs ("ceiling test"). The ceiling test involves comparing the net book value of the fullcost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling limitation is less than the full cost pool, we arerequired to record a ceiling test impairment of our oil and natural gas properties. The full cost ceiling limitation is computed as the sum of the present valueof53Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.estimated future net revenues from our Proved Reserves by applying the average price as prescribed by the SEC Release No. 33-8995, less estimated futureexpenditures (based on current costs) to develop and produce the Proved Reserves, discounted at 10%, plus the cost of properties not being amortized and thelower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects.The ceiling test is computed using the simple average spot price for the trailing 12 month period using the first day of each month. Each of thereference prices for oil and natural gas are further adjusted for quality factors and regional differentials to derive estimated future net revenues. Under full costaccounting rules, any ceiling test impairments of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate ourderivative financial instruments as hedging instruments, we are not allowed to use the impacts of the derivative financial instruments in our ceiling testcomputations.The evaluation of impairment of our oil and natural gas properties includes estimates of Proved Reserves. There are numerous uncertainties inherent inestimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserveestimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing andproduction subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oiland natural gas that are ultimately recovered.GoodwillIn accordance with FASB ASC 350-20, Intangibles-Goodwill and Other, goodwill is not amortized, but is tested for impairment on an annual basis asof December 31, or more frequently as impairment indicators arise. Impairment tests involve the use of estimates related to the fair market value of thebusiness operations with which goodwill is associated. Losses, if any, resulting from impairment tests will be reflected in operating income or loss in theConsolidated Statements of Operations.We apply a two-part, equally weighted approach in determining the fair value of our business as part of the goodwill impairment test. We perform anincome approach, which uses a discounted cash flow model to value our business, and a market approach, in which our value is determined using tradingmetrics and transaction multiples of peer companies. The discounted cash flow model used in the income approach requires us to make various judgmentalassumptions about future production, revenues, operating and capital expenditures, discount rates and other inputs which are based on our budgets, businessplans, economic projections and anticipated future cash flows. The market approach requires us to make assumptions regarding the identifications ofcomparable companies and transactions as well as the future performance of ourselves and the comparable companies. As part of the determination of the fairvalue of our reporting unit, we corroborate the results of the valuation model through a comparison to our enterprise value that is calculated as the combinedmarket capitalization of our equity plus the fair value of our debt. Due to the changing market conditions, it is possible that inputs and assumptions used inthe valuation may change in the future, which could materially affect the estimate of the fair value of our business.Revenue recognition and natural gas imbalancesWe use the sales method of accounting for oil and natural gas revenues. We record sales revenue based on an estimate of the volumes delivered atestimated prices as determined by the applicable sales agreement. We estimate our sales volumes primarily on company-measured volume readings. We thenadjust our oil and natural gas sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received.Historically, these differences have been immaterial. Natural gas imbalances at December 31, 2017, 2016 and 2015 were not significant.Asset retirement obligationsWe follow FASB ASC 410-20, Asset Retirement Obligations ("ASC 410-20") to account for legal obligations associated with the retirement of long-lived assets. ASC 410-20 requires these obligations be recognized at their estimated fair value at the time that the obligations are incurred. The costs ofplugging and abandoning oil and natural gas properties fluctuate with costs associated with the industry. Our calculation of asset retirement obligations usesnumerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, andchanges in the legal, regulatory, environmental and political environments. We periodically assess the estimated costs of our asset retirement obligations andadjust the liability according to these estimates.Income taxesIncome taxes are accounted for in accordance with FASB ASC 740, Income Taxes. Deferred taxes are recorded to reflect54Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.the tax benefits and consequences of future years' differences between the tax basis of assets and liabilities and their financial reporting basis. We must makecertain estimates related to the reversal of temporary differences, and actual results could vary from those estimates. We assess, using all available positiveand negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. Examples of positive and negative evidenceinclude historical taxable income or losses, forecasted income or losses, the estimated timing of the reversals of existing temporary differences as well asprudent and feasible tax planning strategies. We record a valuation allowance to reduce deferred tax assets if it is more likely than not that some portion or allof the deferred tax assets will not be realized. As of December 31, 2017, we continued to have a full valuation allowance against our net deferred tax assets. Asignificant amount of judgment is also required in determining the amount of unrecognized tax benefit to record for uncertain tax positions. We consider theamounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances andinformation available at the reporting date to establish the appropriate amount of unrecognized tax benefit. We currently do not have any uncertain taxpositions recorded as of December 31, 2017.55Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Our results of operationsA summary of key financial data for the years ended December 31, 2017, 2016 and 2015 related to our results of operations is presented below: Year Ended December 31, Year to year change(dollars in thousands, except per unit prices) 2017 2016 2015 2017-2016 2016-2015Production: Oil (Mbbls) 1,158 1,769 2,342 (611) (573)Natural gas (Mmcf) 80,136 93,829 109,926 (13,693) (16,097)Total production (Mmcfe) (1) 87,084 104,443 123,978 (17,359) (19,535)Average daily production (Mmcfe) 239 285 340 (46) (55)Revenues before derivative financial instrument activities: Oil $57,693 $67,317 $102,787 $(9,624) $(35,470)Natural gas 201,137 181,332 226,471 19,805 (45,139)Total oil and natural gas revenues 258,830 248,649 329,258 10,181 (80,609)Purchased natural gas and marketing 24,816 22,352 26,442 2,464 (4,090)Total revenues $283,646 $271,001 $355,700 $12,645 $(84,699)Oil and natural gas derivative financial instruments: Gain (loss) on derivative financial instruments -commodity derivatives $24,732 $(34,137) $75,869 $58,869 $(110,006)Average sales price (before cash settlements of derivative financial instruments): Oil (per Bbl) $49.82 $38.05 $43.89 $11.77 $(5.84)Natural gas (per Mcf) 2.51 1.93 2.06 0.58 (0.13)Natural gas equivalent (per Mcfe) 2.97 2.38 2.66 0.59 (0.28)Costs and expenses: Oil and natural gas operating costs $35,011 $34,609 $53,903 $402 $(19,294)Production and ad valorem taxes 13,131 15,380 22,630 (2,249) (7,250)Gathering and transportation 111,427 106,460 99,321 4,967 7,139Purchased natural gas 23,400 23,557 27,369 (157) (3,812)Depletion 50,066 74,482 213,302 (24,416) (138,820)Depreciation and amortization 974 1,500 2,124 (526) (624)General and administrative 30,165 48,700 58,818 (18,535) (10,118)Interest expense, net 108,175 70,438 106,082 37,737 (35,644)Costs and expenses (per Mcfe): Oil and natural gas operating costs $0.40 $0.33 $0.43 $0.07 $(0.10)Production and ad valorem taxes 0.15 0.15 0.18 — (0.03)Gathering and transportation 1.28 1.02 0.80 0.26 0.22Depletion 0.57 0.71 1.72 (0.14) (1.01)Depreciation and amortization 0.01 0.01 0.02 — (0.01)Net income (loss) $24,362 $(225,258) $(1,192,381) $249,620 $967,123(1)Mmcfe is calculated by converting one barrel of oil into six Mcf of natural gas.The following is a discussion of our financial condition and results of operations for the years ended December 31, 2017, 2016 and 2015.The comparability of our results of operations for 2017, 2016 and 2015 was affected by:•fluctuations in oil and natural gas prices, which impact our oil and natural gas reserves, revenues, cash flows and net income or loss;•impairments of our oil and natural gas properties during 2016 and 2015;56Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.•asset impairments and other non-recurring costs, including the acceleration of costs related to a firm transportation agreement in 2017 and thesettlement of the litigation with a joint venture partner in the Eagle Ford shale during 2016;•gains and losses from derivative financial instruments, including significant gains on the 2017 Warrants due to a decrease in EXCO's share priceduring 2017;•changes in Proved Reserves and production volumes and their impact on depletion;•the sale of our shallow conventional assets in Appalachia and the transfer of interests in connection with the settlement of the litigation with ajoint venture partner in the Eagle Ford shale during 2016;•the impact of declining natural gas production volumes from our reduced drilling activities in certain shale formations;•significant changes in our capital structure as a result of transactions in 2017 and 2016, including the issuance of the 1.5 Lien Notes and SecondLien Term Loan Exchange on March 15, 2017 and repurchases of 2018 Notes and 2022 Notes during 2016 and 2015;•gain on restructuring of debt and accounting treatment for the debt exchange transactions during the fourth quarter of 2015;•changes in general and administrative expenses as a result of legal and professional fees incurred in connection with the restructuring of ourbalance sheet; and•the reductions in our workforce that occurred during 2016 and 2015.GeneralThe availability of a ready market and the prices for oil and natural gas are dependent upon a number of factors that are beyond our control. Thesefactors include, among other things:•supply and demand for oil and natural gas and expectations regarding supply and demand;•the level of domestic and international production;•the availability of imported oil and natural gas;•federal regulations applicable to the export of, and construction of export facilities for natural gas;•political and economic conditions and events in foreign oil and natural gas producing nations, including embargoes, continued hostilities in theMiddle East and other sustained military campaigns, and acts of terrorism or sabotage;•the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;•the cost and availability of transportation and pipeline systems with adequate capacity;•the cost and availability of other competitive fuels;•fluctuating and seasonal demand for oil, natural gas and refined products;•concerns about global warming or other conservation initiatives and the extent of governmental price controls and regulation of production;•regional price differentials and quality differentials of oil and natural gas;•the availability of refining capacity;•technological advances affecting oil and natural gas production and consumption;•weather conditions and natural disasters;•foreign and domestic government relations; and•overall domestic and global economic conditions.Accordingly, in light of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we cannotaccurately predict the prices or marketability of oil and natural gas from any producing well in which we have or may acquire an interest.Marketing arrangementsOn August 19, 2016, we formed Raider through an internal merger to provide marketing services to EXCO and pursue independent businessopportunities. Raider is a wholly owned subsidiary of EXCO and is the contractual counterparty by operation of Texas law to all of EXCO's gathering,transportation and marketing contracts in Texas and Louisiana. Raider purchases and resells natural gas from third-party producers as well as oil and naturalgas from operated wells in Texas and Louisiana, and charges a fee for marketing services to certain working interest owners in the related wells.We produce oil and natural gas. We do not refine or process the oil or natural gas we produce. We sell the majority of the oil we produce undercontracts using market sensitive pricing. The majority of our oil contracts are based on NYMEX pricing, which is typically calculated as the average of thedaily closing prices of oil to be delivered one month in the future. We also57Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.sell a portion of our oil at F.O.B. field prices posted by the principal purchaser of oil where our producing properties are located. Our sales contracts are of atype common within the industry, and we usually negotiate a separate contract for each area. Generally, we sell our oil to purchasers and refiners near theareas of our producing properties.We sell the majority of our natural gas under individually negotiated gas purchase contracts using market sensitive pricing. Our sales contracts vary inlength from spot market sales of a single day to term agreements that may extend for a year or more. Our natural gas customers primarily include natural gasmarketing companies. The natural gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas soldon the spot market varies daily, reflecting changing market conditions.We may be unable to market all of the oil or natural gas we produce. If our oil and natural gas can be marketed, we may be unable to negotiatefavorable pricing and contractual terms. Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and naturalgas properties and the estimates of recoverable oil and natural gas reserves. Further, significant declines in the prices of oil or natural gas may have a materialadverse effect on our business and on our financial condition.We engage in oil and natural gas production activities in geographic regions where, from time to time, the supply of oil or natural gas available fordelivery exceeds the demand. If this occurs, companies purchasing oil or natural gas in these areas may reduce the amount of oil or natural gas that theypurchase from us. If we cannot locate other buyers for our production or for any of our oil or natural gas reserves, we may shut in our oil or natural gas wellsfor certain periods of time. Furthermore, we may shut in our oil and natural gas wells if regional market prices decrease to a level that is uneconomical toproduce. If this occurs, we may incur additional payment obligations under our oil and natural gas leases and, under certain circumstances, the oil and naturalgas leases might be terminated. Economic conditions, particularly depressed oil and natural gas prices, may negatively impact the liquidity andcreditworthiness of our purchasers and may expose us to risk with respect to the ability to collect payments for the oil and natural gas we deliver.Oil and natural gas production, revenues and pricesThe following table presents our production, revenue and average sales prices for the years ended December 31, 2017 and 2016: Year Ended December 31, 2017 2016 Year to year change(dollars in thousands, except perunit rate) Production(Mmcfe) Revenue $/Mcfe Production(Mmcfe) Revenue $/Mcfe Production(Mmcfe) Revenue $/McfeProducing region: North Louisiana 53,373 $138,653 $2.60 55,314 $110,755 $2.00 (1,941) $27,898 $0.60East Texas 16,106 45,026 2.80 24,454 54,944 2.25 (8,348) (9,918) 0.55South Texas 7,742 54,084 6.99 11,471 62,037 5.41 (3,729) (7,953) 1.58Appalachia and other 9,863 21,067 2.14 13,204 20,913 1.58 (3,341) 154 0.56 Total 87,084 $258,830 $2.97 104,443 $248,649 $2.38 (17,359) $10,181 $0.59Production for the year ended December 31, 2017 decreased by 17.4 Bcfe, or 17%, as compared with 2016. The decrease in production was primarilydue to limited development activities in recent years as a result of the depressed oil and natural gas price environment and liquidity constraints. Significantcomponents of the changes in production were a result of:•decreased production of 1.9 Bcfe for the year ended December 31, 2017 in the North Louisiana region primarily due to production declinespartially offset by additional volumes from the wells turned-to-sales in 2017. We expect production in the North Louisiana region to increase dueto additional wells turned-to-sales during the fourth quarter of 2017 and first quarter of 2018.•decreased production of 8.3 Bcfe for the year ended December 31, 2017 in the East Texas region primarily due to production declines as we havenot turned an operated well to sales in the region since the first quarter of 2016.•decreased production of 3.7 Bcfe for the year ended December 31, 2017 in the South Texas region primarily due to production declines as we havenot turned an operated well to sales in the region since late 2015. We expect production in the South Texas region to increase due to additionalwells turned-to-sales during the first half of 2018.•decreased production of 3.3 Bcfe for the year ended December 31, 2017 in the Appalachia region primarily due to the sale of our interests inshallow conventional assets in 2016 and production declines, partially offset by lower58Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.shut-in volumes. We have not had an active drilling program in this region since 2013. Production in the Appalachia region was impacted bysignificant shut-in volumes during the fourth quarters of 2017 and 2016 due to low regional natural gas prices.Oil and natural gas revenues for the year ended December 31, 2017 increased by $10.2 million, or 4%, as compared with 2016. The increase inrevenues was primarily the result of increases in commodity prices offset by oil and natural gas production declines. Our average natural gas sales priceincreased 30% to $2.51 per Mcf for the year ended December 31, 2017 from $1.93 per Mcf for the year ended December 31, 2016, primarily due to highermarket prices. Our average sales price of oil per Bbl increased 31% to $49.82 per Bbl for the year ended December 31, 2017 from $38.05 per Bbl for the yearended December 31, 2016, primarily due to higher market prices.The following table and discussion presents our production, revenue and average sales prices for the years ended December 31, 2016 and 2015: Year Ended December 31, 2016 2015 Year to year change(dollars in thousands, except perunit rate) Production(Mmcfe) Revenue $/Mcfe Production(Mmcfe) Revenue $/Mcfe Production(Mmcfe) Revenue $/McfeProducing region: North Louisiana 55,314 $110,755 $2.00 73,896 $160,612 $2.17 (18,582) $(49,857) $(0.17)East Texas 24,454 54,944 2.25 18,275 45,656 2.50 6,179 9,288 (0.25)South Texas 11,471 62,037 5.41 15,220 96,008 6.31 (3,749) (33,971) (0.90)Appalachia and other 13,204 20,913 1.58 16,587 26,982 1.63 (3,383) (6,069) (0.05) Total 104,443 $248,649 $2.38 123,978 $329,258 $2.66 (19,535) $(80,609) $(0.28)Production for the year ended December 31, 2016 decreased by 19.5 Bcfe, or 16%, as compared with 2015. The decrease in our production wasprimarily attributable to a reduction in our capital expenditures of 72% compared to prior year in response to the lower oil and natural gas price environment.Significant components of the changes in production included:•decreased production of 18.6 Bcfe for the year ended December 31, 2016 in the North Louisiana region primarily due to production declinespartially offset by additional volumes from the wells turned-to-sales during 2016.•increased production of 6.2 Bcfe for the year ended December 31, 2016 in the East Texas region primarily due to additional volumes from wellsturned-to-sales during late 2015 and early 2016.•decreased production of 3.7 Bcfe for the year ended December 31, 2016 in the South Texas region primarily due to production declines and thetransfer of a portion of our interests in certain producing wells to a joint venture partner. The transfer of our interests was the result of the litigationsettlement with a joint venture partner that is described in more detail in "Note 3. Acquisitions, divestitures and other significant events" in theNotes to our Consolidated Financial Statements.•decreased production of 3.4 Bcfe for the year ended December 31, 2016 in the Appalachia region primarily due to the sale of our interests inshallow conventional assets located in Pennsylvania and West Virginia in 2016 and production declines.Oil and natural gas revenues for the year ended December 31, 2016 decreased by $80.6 million, or 24%, as compared with 2015. The decrease inrevenues was primarily the result of decreases in oil and natural gas production and prices. Our average natural gas sales price decreased 6% to $1.93 per Mcffor the year ended December 31, 2016 from $2.06 per Mcf for the year ended December 31, 2015, primarily due to lower market prices. Our average salesprice of oil per Bbl decreased 13% to $38.05 per Bbl for the year ended December 31, 2016 from $43.89 per Bbl for the year ended December 31, 2015,primarily due to lower market prices.Purchased natural gas and marketing revenuesPurchased natural gas and marketing revenues include revenues we receive as a result of selling natural gas purchased from third parties and marketingfees we receive from third parties. Purchased natural gas and marketing revenues for the year ended December 31, 2017 increased by $2.5 million, or 11%, ascompared with 2016, primarily due to higher natural gas prices and marketing fees charged to third parties beginning in September 2016, partially offset bylower volumes purchased. Purchased natural gas and marketing revenues for the year ended December 31, 2016 decreased by $4.1 million, or 15%, as59Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.compared to 2015, primarily due to lower volumes sold partially offset by marketing fees charged to third parties beginning in September 2016.Oil and natural gas operating costsThe following tables and discussion present our oil and natural gas operating costs for the years ended December 31, 2017, 2016, and 2015. Year Ended December 31, 2017 2016 Year to year change(in thousands) Leaseoperatingexpenses Workovers andother Total Leaseoperatingexpenses Workovers andother Total Leaseoperatingexpenses Workovers andother TotalProducing region: North Louisiana $14,055 $3,130 $17,185 $11,467 $1,050 $12,517 $2,588 $2,080 $4,668East Texas 4,585 828 5,413 5,082 596 5,678 (497) 232 (265)South Texas 10,677 4 10,681 11,405 246 11,651 (728) (242) (970)Appalachia and other 1,694 38 1,732 4,692 71 4,763 (2,998) (33) (3,031)Total $31,011 $4,000 $35,011 $32,646 $1,963 $34,609 $(1,635) $2,037 $402 Year Ended December 31, 2017 2016 Year to year change(per Mcfe) Leaseoperatingexpenses Workovers andother Total Leaseoperatingexpenses Workovers andother Total Leaseoperatingexpenses Workovers andother TotalProducing region: North Louisiana $0.26 $0.06 $0.32 $0.21 $0.02 $0.23 $0.05 $0.04 $0.09East Texas 0.28 0.05 0.33 0.21 0.02 0.23 0.07 0.03 0.10South Texas 1.38 — 1.38 0.99 0.02 1.01 0.39 (0.02) 0.37Appalachia and other 0.17 — 0.17 0.36 0.01 0.37 (0.19) (0.01) (0.20)Total $0.36 $0.04 $0.40 $0.31 $0.02 $0.33 $0.05 $0.02 $0.07Oil and natural gas operating costs for the year ended December 31, 2017 increased by $0.4 million, or 1%, as compared with 2016. The increase wasprimarily due to higher workover activity, partially offset by lower lease operating expenses due to the sale of our conventional assets in the Appalachiaregion during 2016.60Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. Year Ended December 31, 2016 2015 Year to year change(in thousands) Leaseoperatingexpenses Workovers andother Total Leaseoperatingexpenses Workovers andother Total Leaseoperatingexpenses Workoversand other TotalProducing region: North Louisiana $11,467 $1,050 $12,517 $13,342 $2,798 $16,140 $(1,875) $(1,748) $(3,623)East Texas 5,082 596 5,678 4,097 1,426 5,523 985 (830) 155South Texas 11,405 246 11,651 18,768 2,007 20,775 (7,363) (1,761) (9,124)Appalachia and other 4,692 71 4,763 10,850 615 11,465 (6,158) (544) (6,702)Total $32,646 $1,963 $34,609 $47,057 $6,846 $53,903 $(14,411) $(4,883) $(19,294) Year Ended December 31, 2016 2015 Year to year change(per Mcfe) Leaseoperatingexpenses Workovers andother Total Leaseoperatingexpenses Workovers andother Total Leaseoperatingexpenses Workoversand other TotalProducing region: North Louisiana $0.21 $0.02 $0.23 $0.18 $0.04 $0.22 $0.03 $(0.02) $0.01East Texas 0.21 0.02 0.23 0.22 0.08 0.30 (0.01) (0.06) (0.07)South Texas 0.99 0.02 1.01 1.23 0.13 1.36 (0.24) (0.11) (0.35)Appalachia and other 0.36 0.01 0.37 0.65 0.04 0.69 (0.29) (0.03) (0.32)Total $0.31 $0.02 $0.33 $0.38 $0.05 $0.43 $(0.07) $(0.03) $(0.10)Oil and natural gas operating costs for the year ended December 31, 2016 decreased by $19.3 million, or 36%, as compared with 2015. The decreasewas primarily due to cost reduction efforts, including significant reductions in labor costs, repair and maintenance costs, chemical treatment costs, workoveractivity and saltwater disposal costs. Reduced labor costs were primarily due to significant reductions in our workforce in 2015 and 2016. The sale of ourconventional assets in Appalachia in 2016 also contributed to lower oil and natural gas operating costs in the region, including the associated reductions inour workforce. On a consolidated basis, our net share of labor costs for the year ended December 31, 2016 decreased by $4.6 million, or 51%, as comparedwith 2015. The reduction in saltwater disposal costs is primarily due to the renegotiation of contracts and more cost-efficient disposal methods.Production and ad valorem taxes Year Ended December 31, 2017 2016 2015(in thousands, except per unitrate) Productionand advalorem taxes % ofrevenue Taxes$/Mcfe Productionand advalorem taxes % ofrevenue Taxes$/Mcfe Productionand advalorem taxes % ofrevenue Taxes$/McfeProducing region: North Louisiana $6,936 5.0% $0.13 $7,482 6.8% $0.14 $10,027 6.2% $0.14East Texas 1,291 2.9% 0.08 1,467 2.7% 0.06 1,059 2.3% 0.06South Texas 4,300 8.0% 0.56 5,709 9.2% 0.50 10,216 10.6% 0.67Appalachia and other 604 2.9% 0.06 722 3.5% 0.05 1,328 4.9% 0.08Total $13,131 5.1% $0.15 $15,380 6.2% $0.15 $22,630 6.9% $0.18Production and ad valorem taxes for the year ended December 31, 2017 decreased by $2.2 million, or 15%, as compared with 2016. The decrease wasprimarily due to lower production volumes offset by higher commodity prices, and lower ad valorem taxes in South Texas. The higher oil prices primarilyimpacted properties located in Texas because production taxes are based on a fixed percentage of gross value of production sold. Production and ad valoremtaxes for the year ended December 31, 2016 decreased by $7.3 million, or 32%, as compared with 2015. The decrease was primarily due to lower productionvolumes and lower commodity prices.61Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Production and ad valorem tax rates per Mcfe were $0.15, $0.15 and $0.18 for 2017, 2016 and 2015, respectively. The decrease from 2015 to 2016 wasprimarily due to lower ad valorem taxes in South Texas.In our North Louisiana and East Texas regions, we currently receive severance tax holidays on certain horizontal wells which reduce the effective rateof these taxes. Our horizontal wells in the state of Louisiana are eligible for an exemption from severance taxes for the earlier of two years from the date offirst production or until payout of qualified costs. In July 2015, the state of Louisiana decreased its severance tax rate for wells that do not receive exemptionsfrom $0.163 to $0.158 per Mcf. The effective severance tax rate decreased to $0.098 per Mcf in July 2016 and increased to $0.111 per Mcf in July 2017. Ourhorizontal natural gas wells in the state of Texas are eligible for an exemption from severance taxes for up to ten years of production or until the cumulativevalue of the tax reduction equals 50% of the drilling and completion costs incurred for the well.Production and ad valorem taxes are set by state and local governments and vary as to the tax rate and the value to which that rate is applied. InLouisiana, where a substantial percentage of our production is derived, severance taxes are levied on a per Mcf basis. Therefore, the resulting dollar value ofproduction is not sensitive to changes in prices for natural gas, except for holiday exemptions, if any. In our other operating areas, particularly Texas,production taxes are based on a fixed percentage of gross value of production sold. As such, our realized severance and ad valorem tax rates may becomemore sensitive to prices, except for wells that receive holiday exemptions, if any. The Commonwealth of Pennsylvania requires an impact fee to be paid on allunconventional wells spud based on a price tier calculation for a period of 15 years. Multiple pieces of legislation have been introduced in both thePennsylvania House and the Senate that propose a severance tax at varying rates on the production of oil and natural gas. This severance tax would likely bein addition to the impact fee and could have an impact on our production taxes in future periods. There is no certainty that this legislation will pass, nor is itpossible to quantify the impact at this time.Gathering and transportationGathering and transportation expenses for the year ended December 31, 2017 increased by $5.0 million, or 5%, as compared with 2016. The increasewas primarily due to gathering expenses in connection with taking our gas in-kind from certain third-party operated wells in the North Louisiana region,shortfall fees under an agreement to deliver an aggregate minimum volume commitment of natural gas production to certain gathering systems in East Texasand North Louisiana, and higher variable gathering costs on volumes from wells turned-to-sales in North Louisiana. If we utilize the gathering contract withthe minimum volume commitment, these costs are allocated amongst the owners that incur these types of costs. If we do not utilize the gathering contractwith the minimum volume commitment, we incur the entire amount of the shortfall fees and these costs are not allocated to other owners. Gathering andtransportation expenses were $1.28 per Mcfe for the year ended December 31, 2017, as compared to $1.02 per Mcfe for the year ended December 31, 2016.Gathering and transportation expenses for the year ended December 31, 2016 increased by $7.1 million, or 7%, as compared with 2015. The increasewas primarily due to gathering expenses in connection with taking our gas in-kind from certain third-party operated wells in the North Louisiana region, andhigher variable gathering costs on volumes from wells turned-to-sales in North Louisiana. Gathering and transportation expenses were $1.02 per Mcfe for theyear ended December 31, 2016, as compared to $0.80 per Mcfe for the year ended December 31, 2015. The increase was primarily due to lower volumes inrelation to fixed costs under gathering and firm transportation contracts in the East Texas and North Louisiana regions.As discussed in "Note 8. Commitments and contingencies" in the Notes to our Consolidated Financial Statements, we terminated certain sales and firmtransportation agreements during the third quarter of 2016 that are currently subject to litigation. The termination of these contracts will not be reflected inour financial results until the litigation is resolved and it is deemed to be realized in accordance with GAAP. On January 18, 2018 and March 1, 2018, theCompany and the Filing Subsidiaries filed motions to reject certain executory contracts as permitted under the Bankruptcy Code, including certain gatheringand transportation contracts. Certain of these transportation contracts were rejected by the Court on March 7, 2018, and a hearing to consider the motion toreject additional gathering and transportation contracts is scheduled for March 29, 2018. The rejection of these contracts is expected to significantly decreaseour gathering and transportation expenses in future periods. See further discussion of the motion to reject these contracts in "Note 17. Subsequent events" inthe Notes to our Consolidated Financial Statements.Purchased natural gas expensesPurchased natural gas expenses are purchases of natural gas from third parties plus the related costs of transportation. Purchased natural gas expensesfor the year ended December 31, 2017 decreased by $0.2 million, or 1%, as compared with62Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.2016, primarily due to lower volumes purchased. Purchased natural gas expenses for the year ended December 31, 2016 decreased by $3.8 million, or 14%, ascompared with 2015, primarily due to lower purchase prices.Depletion, depreciation and amortizationDepletion, depreciation and amortization for the year ended December 31, 2017 decreased as compared with 2016 primarily due to a decrease indepletion expense of $24.4 million, or 33%. On a per Mcfe basis, the depletion rate for the year ended December 31, 2017 was $0.57 per Mcfe, compared with$0.71 per Mcfe in 2016. The decrease in depletion expense was primarily due to a decrease in production and the depletion rate. The decrease in thedepletion rate was primarily related to higher proved reserve volumes and impairments of our oil and natural gas properties during 2016, which lowered ourdepletable base.Depletion, depreciation and amortization for the year ended December 31, 2016 decreased as compared with 2015 primarily due to a decrease indepletion expense of $139.4 million, or 17%. On a per Mcfe basis, the depletion rate for the year ended December 31, 2016 was $0.71 per Mcfe, comparedwith $1.72 per Mcfe in 2015. The decrease in depletion expense was primarily due to impairments of our oil and natural gas properties during 2016 and2015, which lowered our depletable base.Impairment of oil and natural gas propertiesFor the year ended December 31, 2017, we did not record impairments to our oil and natural gas properties primarily due to an increase in oil andnatural gas prices. The trailing twelve month reference price of $2.98 per Mmbtu for natural gas and $51.34 per Bbl of oil for the year ended December 31,2017 increased from $2.48 per Mmbtu for natural gas and $42.75 per Bbl of oil for the year ended December 31, 2016. For the years ended December 31,2016 and 2015, we recorded impairments to our oil and natural gas properties of $160.8 million and $1.2 billion, respectively, primarily due to thesignificant decline in oil and natural gas prices and the related downward revisions to the reserves of our oil and gas properties due to changes in prices.Oil and natural gas prices are volatile and we may incur additional impairments during 2018 if future oil and natural gas prices result in a decrease inthe trailing twelve-month reference prices compared to December 31, 2017. For the first quarter 2018, the trailing twelve month reference prices expected tobe utilized in our first quarter 2018 ceiling test calculation are approximately $3.00 per Mmbtu for natural gas and $53.49 per Bbl of oil, representing anincrease of 1% and 4% for the price of natural gas and oil, respectively, from December 31, 2017. The possibility and amount of any future impairment isdifficult to predict, and will depend, in part, upon future oil and natural gas prices to be utilized in the ceiling test, estimates of Proved Reserves and futurecapital expenditures and operating costs.General and administrativeThe following table presents our general and administrative expenses for the years ended December 31, 2017, 2016 and 2015: Year Ended December 31, Year to year change(in thousands, except per unit rate) 2017 2016 2015 2017-2016 2016-2015General and administrative costs: Gross general and administrative expense $65,484 $58,002 $87,788 $7,482 $(29,786)Technical services and service agreement charges (6,386) (7,132) (15,884) 746 8,752Operator overhead reimbursements (14,585) (13,703) (13,126) (882) (577)Capitalized salaries (2,918) (3,245) (7,158) 327 3,913General and administrative expense, excluding equity-based compensation 41,595 33,922 51,620 7,673 (17,698)Gross equity-based compensation (10,430) 15,530 10,626 (25,960) 4,904Capitalized equity-based compensation (1,000) (752) (3,428) (248) 2,676General and administrative expense $30,165 $48,700 $58,818 $(18,535) $(10,118)63Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.General and administrative expenses for the year ended December 31, 2017 decreased by $18.5 million, or 38%, compared with 2016. Significantcomponents of the changes in general and administrative expense for the year ended December 31, 2017 compared to 2016 were a result of:•increased personnel costs of $2.8 million for the year ended December 31, 2017 compared to the same period in the prior year, primarily due tohigher bonus expense during the current year, partially offset by lower headcount. The increase in bonus expense was due to the adoption of newcash-based retention and incentive plans in connection with our restructuring activities. The cash-based retention and incentive plans areintended to replace grants under the equity-based incentive plans. As a result, we expect cash-based personnel costs to increase and equity-basedcompensation expense to decrease in future periods. See "Note 11. Equity-based and other incentive-based compensation" in the Notes to ourConsolidated Financial Statements for additional information.•increased professional and legal fees of $8.3 million for the year ended December 31, 2017 compared to the same period in the prior year,primarily related to the legal and advisory fees incurred in connection with restructuring activities. We will be required to incur substantial costsfor professional fees and other expenses associated with the administration of the Chapter 11 proceedings. In addition to the legal and financialadvisors hired to represent us, we are required to pay the costs related to the legal and financial advisors of certain of our creditors. As a result, weexpect professional and legal fees to increase significantly in future periods.•decreased various other gross general and administrative expenses of $3.6 million for the year ended December 31, 2017 compared to the sameperiod in the prior year. These decreases reflect our efforts to reduce our general and administrative costs throughout the organization.•decreased equity-based compensation of $26.0 million for the year ended December 31, 2017 compared to the same period in the prior year. Thedecrease was primarily due to income of $14.5 million for the year ended December 31, 2017 compared to expense of $11.3 million for the yearended December 31, 2016 for the ESAS Warrants. The fair value of the warrants is dependent on factors such as our share price, historicalvolatility, risk-free rate and performance relative to our peer group. The income related to these warrants in 2017 was primarily due to a decline infair value as a result of a significant decrease in EXCO's common share price. Furthermore, the ESAS Warrants were forfeited and canceled andpreviously recognized compensation costs were reversed.General and administrative expenses for the year ended December 31, 2016 decreased by $10.1 million, or 17%, compared with 2015. Significantcomponents of the changes in general and administrative expense for the year ended December 31, 2016 compared to 2015 were a result of:•decreased personnel costs of $29.8 million for the year ended December 31, 2016 compared to the same period in the prior year, primarily due toreductions in our workforce and employee benefits, including the suspension of the 401(K) employer match.•increased professional and legal fees of $6.7 million for the year ended December 31, 2016 compared to the same period in the prior year,primarily related to the legal and advisory fees incurred in connection with the strategic initiatives focused on restructuring our balance sheet andgathering and transportation contracts;•decreased various other gross general and administrative expenses of $6.7 million for the year ended December 31, 2016 compared to the sameperiod in the prior year. These decreases reflect our efforts to reduce our general and administrative costs throughout the organization.•decreased technical services and service agreement recoveries of $8.8 million for the year ended December 31, 2016 compared to the same periodin the prior year. These decreases were primarily a result of reduced headcount and lower recoveries in connection with the transition serviceagreement with a former joint venture that terminated in April 2015.•decreased capitalized salaries of $3.9 million and capitalized equity-based compensation of $2.7 million for the year ended December 31, 2016compared to the same period in the prior year, primarily as a result of reduced employee headcount; and•increased equity-based compensation of $4.9 million for the year ended December 31, 2016 compared to the same period in the prior year. Theincrease was primarily due to $8.1 million of additional compensation expense related to the warrants issued to ESAS in 2015. The increase in ourequity-based compensation expense was partially offset by lower equity-based compensation to employees as a result of reductions in ourworkforce.Other operating itemsOther operating items were net losses of $59.2 million, $24.2 million and $0.5 million for the years ended December 31, 2017, 2016 and 2015,respectively. The net loss for the year ended December 31, 2017 was primarily due to the acceleration of the remaining $56.4 million in costs under a firmtransportation agreement. See further discussion in "Note 8. Commitment and contingencies" in the Notes to our Consolidated Financial Statements. The netloss for the year ended December 31, 2016 was64Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.primarily due to the settlement of the litigation with a joint venture partner in the Eagle Ford shale. See "Note 3. Acquisitions, divestitures and othersignificant events" in the Notes to our Consolidated Financial Statements for additional information. The net loss for the year ended December 31, 2015primarily consisted of legal expenses and other assessments partially offset by income from surface acreage that we own in the South Texas region.Interest expense, netThe following table presents our interest expense for the years ended December 31, 2017, 2016 and 2015: Year Ended December 31, Year to year change(in thousands) 2017 2016 2015 2017-2016 2016-2015Interest expense, net: EXCO Resources Credit Agreement $4,554 $5,909 $6,747 $(1,355) $(838)1.5 Lien Notes 39,480 — — 39,480 —1.75 Lien Term Loans 36,228 — — 36,228 —Fairfax Term Loan 7,708 37,611 6,764 (29,903) 30,8472018 Notes 10,157 10,612 50,381 (455) (39,769)2022 Notes 5,964 12,294 38,338 (6,330) (26,044)Amortization of deferred financing costs 10,198 8,989 15,729 1,209 (6,740)Capitalized interest (6,440) (5,213) (12,040) (1,227) 6,827Other 326 236 163 90 73Total interest expense, net $108,175 $70,438 $106,082 $37,737 $(35,644)Interest expense, net for the year ended December 31, 2017 increased $37.7 million from 2016. Significant components of the changes in interestexpense, net for the year ended December 31, 2017 compared to 2016 were a result of additional interest expense on the 1.5 Lien Notes and 1.75 Lien TermLoans partially as a result of higher interest rates associated with PIK Payments. This was partially offset by lower interest expense on the 2018 Notes and2022 Notes due to lower outstanding balances as a result of note repurchases that occurred during 2016, lower average outstanding balances on the EXCOResources Credit Agreement, and the Fairfax Term Loan. The Fairfax Term Loan was terminated as a result of the Second Lien Term Loan Exchange.Interest expense, net for the year ended December 31, 2016 decreased $35.6 million from the same period in 2015. Significant components of thechanges in interest expense, net for the year ended December 31, 2016 compared to 2015 were a result of lower outstanding balances on the 2018 Notes and2022 Notes from debt restructuring activities and note repurchases in 2015 and 2016. This was partially offset by additional interest from the 12.5% seniorsecured Second Lien Term Loan with certain affiliates of Fairfax Financial Holdings Limited in the aggregate principal amount of $300.0 million ("FairfaxTerm Loan"), which closed in the fourth quarter of 2015. The decreases were also partially offset by lower capitalized interest primarily related to lowerbalances of unproved oil and natural gas properties and suspension of our drilling and development program in certain areas.The Exchange Term Loans and a portion of the 1.75 Lien Term Loans are accounted for as a troubled debt restructuring pursuant to ASC 470-60,Troubled Debt Restructuring by Debtors. As such, the carrying amounts of the Exchange Term Loan and a portion of the 1.75 Lien Term Loans, whetherdesignated as interest or as principal amount, are adjusted each time we make a payment. Interest expense is recognized on this portion of the 1.75 Lien TermLoans if the fair value of the PIK Payments exceeds the interest capitalized as part of the carrying value.As a result of the bankruptcy proceedings, the Court may limit post-petition interest on debt that may be under secured or unsecured. On February 22,2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes. Furthermore, asignificant portion of our indebtedness may be repaid, canceled or equitized as a result of the Chapter 11 Cases. Therefore, our interest expense may decreasein future periods.Gain (loss) on derivative financial instruments - commodity derivativesOur oil and natural gas derivative financial instruments resulted in net gains of $24.7 million, net losses of $34.1 million and net gains of $75.9million for the years ended December 31, 2017, 2016 and 2015, respectively. Based on the nature of our derivative contracts, decreases in the relatedcommodity price typically result in increases to the value of our derivatives contracts. The significant fluctuations demonstrate the high volatility in oil andnatural gas prices between each of the periods.65Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.The ultimate settlement amount of the unrealized portion of the derivative financial instruments is dependent on future commodity prices.The following table presents our natural gas prices, before and after the impact of the cash settlement of our derivative financial instruments. Year Ended December 31, Year to year changeAverage realized pricing: 2017 2016 2015 2017-2016 2016-2015Natural gas (per Mcf): Net price, excluding derivatives $2.51 $1.93 $2.06 $0.58 $(0.13)Cash receipts (payments) on derivatives (0.05) 0.24 0.74 (0.29) (0.50)Net price, including derivatives $2.46 $2.17 $2.80 $0.29 $(0.63)Oil (per Bbl): Net price, excluding derivatives $49.82 $38.05 $43.89 $11.77 $(5.84)Cash receipts on derivatives (0.15) 9.24 20.12 (9.39) (10.88)Net price, including derivatives $49.67 $47.29 $64.01 $2.38 $(16.72)Natural gas equivalent (per Mcfe): Net price, excluding derivatives $2.97 $2.38 $2.66 $0.59 $(0.28)Cash receipts (payments) on derivatives (0.05) 0.37 1.04 (0.42) (0.67)Net price, including derivatives $2.92 $2.75 $3.70 $0.17 $(0.95)Our net cash payments for 2017 were $4.1 million, or $0.05 per Mcfe, compared to net cash receipts of $39.1 million, or $0.37 per Mcfe, in 2016 andnet cash receipts of $128.8 million, or $1.04 per Mcfe, in 2015. The differences between cash payments and cash receipts during 2017 and 2016 wereprimarily due to lower volumes hedged and higher oil and natural gas prices in the current period. The differences between the cash receipts during 2016 and2015 were primarily due to lower volumes hedged and lower strike prices during 2016.Gain on derivative financial instruments - common share warrantsPursuant to ASC 815, we account for the warrants issued in connection with the issuance of the 1.5 Lien Notes and 1.75 Lien Term Loans during 2017as derivative instruments and carry the warrants as a non-current liability at their fair value, with the increase or decrease in fair value being recognized inearnings. These warrants are measured at fair value on a recurring basis until the date of exercise or the date of expiration. We recorded a gain on therevaluation of the warrants of $159.2 million during the year ended December 31, 2017, primarily due to a decrease in EXCO's share price.Gain (loss) on restructuring and extinguishment of debtFor the year ended December 31, 2017, we recorded a net loss on extinguishment of debt of $6.4 million. The net loss was primarily due to third-partyfees incurred in connection with the Second Lien Term Loan Exchange. The exchange was accounted for as a modification of debt, and as a result, third-partyfees were immediately expensed.For the year ended December 31, 2016, we recorded a net gain on extinguishment of debt of $119.5 million. The net gain was primarily due to therepurchases of an aggregate of $179.1 million in principal amount of the 2018 Notes and 2022 Notes with an aggregate of $53.3 million in cash.For the year ended December 31, 2015, we recorded a net gain of $193.3 million. We repurchased a portion of the outstanding 2018 Notes and 2022Notes in exchange for the holders of such notes agreeing to act as lenders in connection with the Exchange Term Loan which resulted in a net gain of $165.1million. Additionally, in the fourth quarter of 2015, we repurchased $40.8 million in principal of the 2018 Notes through open market repurchases with $12.0million in cash resulting in a $28.2 million net gain on extinguishment of debt. The net gains on the transactions during 2016 and 2015 included anacceleration of the related deferred financing costs and notes discount, as well as direct costs associated with the transactions.Equity lossOur equity loss was $4.2 million, $16.4 million, and $15.7 million for the years ended December 31, 2017, 2016 and 2015, respectively. Our equityloss for the year ended December 31, 2017 was primarily comprised of impairments of $5.2 million of EXCO's interest in a midstream investment in the EastTexas and North Louisiana regions.66Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Our equity loss for the year ended December 31, 2016 was primarily comprised of impairments of $9.6 million to our midstream investments in theAppalachia region and the East Texas and North Louisiana regions. In addition, we had an impairment of $1.7 million to our investment that serves as theoperator and owns an interest in our Appalachia assets ("OPCO") and a net loss of $2.8 million for the year ended December 31, 2016 from our equity methodinvestment that owns and manages certain surface acreage in the North Louisiana region primarily due to its impairment of certain assets.Our equity loss for the year ended December 31, 2015 was primarily due to other than temporary impairments of our midstream investments in theAppalachia region and the East Texas and North Louisiana regions. The impairments were recorded to reduce the carrying values to the fair values.The impairments were recorded to reduce the carrying values to the fair values. For additional discussion of our impairments, see "Note 6. Fair valuemeasurements" in the Notes to our Consolidated Financial Statements.Income taxesThe following table presents a reconciliation of our income tax provision (benefit) for the years ended December 31, 2017, 2016 and 2015: Year Ended December 31,(in thousands) 2017 2016 2015Federal income taxes (benefit) provision at statutory rate of 35% $8,630 $(77,860) $(417,333)Increases (reductions) resulting from: Adjustments to the valuation allowance (525,674) 82,459 459,843Non-deductible compensation 3,206 5,019 2,399State taxes net of federal benefit (1,496) (7,637) (45,009)Federal and state tax rate change 421,610 — —Non-deductible interest 149,577 — —Non-taxable gain on warrants (55,716) — —Other 159 821 100Total income tax provision $296 $2,802 $—During the year ended December 31, 2017, we recognized a current income tax benefit of $1.4 million due to refunds for alternative minimum taxcredits. During the years ended December 31, 2017 and 2016, we recognized deferred income tax expense of $1.7 million and $2.8 million, respectively,related to a deferred tax liability for tax deductible goodwill. During the year ended December 31, 2016, the book basis of goodwill exceeded the tax basisthat caused the previous book and tax basis differences to change from a deferred tax asset to a deferred tax liability. The deferred tax liability related togoodwill is considered to have an indefinite life based on the nature of the underlying asset and cannot be offset under GAAP with a deferred tax asset with adefinite life, such as NOLs. However, the deferred income tax expense is not expected to result in cash payments of income taxes in the foreseeable future. Year Ended December 31,(in thousands) 2017 2016 2015Income tax expense (benefit): Current income tax benefit $(1,420) $— $—Deferred income tax expense 1,716 2,802 —Total income tax expense $296 $2,802$—During the years ended 2017, 2016 and 2015, we recognized a full valuation allowance against our net deferred tax assets. The utilization of our NOLsto offset taxable income in future periods may be limited if we undergo an ownership change based on the criteria in Section 382 of the Internal RevenueCode. See further discussion of the potential limitations on the utilization of our net operating losses as part of "Item 1A. Risk Factors".67Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.As of December 31, 2017, 2016 and 2015, there were no unrecognized tax benefits, including interest and penalties that would be required to berecognized in our financial statements.On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act ("Tax Act") which, among other things, lowered the U.S. Federal tax ratefrom 35% to 21%, repealed the corporate alternative minimum tax, and provided for a refund of previously accrued alternative minimum tax credits. We arestill analyzing certain aspects of the Tax Act, which could potentially affect the measurement of our income tax balances and future income tax expense orbenefit. See further discussion of the Tax Act in "Note 12. Income taxes" in the Notes to our Consolidated Financial Statements.Our Liquidity, capital resources and capital commitmentsOverviewOur primary sources of capital resources and Liquidity have historically consisted of internally generated cash flows from operations, borrowingsunder certain credit agreements, issuances of debt securities, dispositions of non-strategic assets, joint ventures and capital markets when conditions arefavorable. Our ability to issue additional indebtedness, dispose assets, enter into joint ventures or access the capital markets may be substantially limited ornonexistent during our Chapter 11 proceedings and will require court approval in most instances. Accordingly, our Liquidity will depend mainly on cashgenerated from operating activities and available funds under the DIP Credit Agreement. Factors that could impact our Liquidity, capital resources andcapital commitments include the following:•the outcome of potential strategic alternatives to maximize value for the benefit of our stakeholders as part of the Chapter 11 process, which mayinclude a sale of certain or substantially all of our assets under Section 363 of the Bankruptcy Code, a plan of reorganization to equitize certainindebtedness, or a combination thereof;•significant costs associated with the bankruptcy process, including our ability to limit these costs by obtaining confirmation of a successful planof reorganization in timely manner;•decisions from the Court related to requirements to pay interest on certain debt instruments during the bankruptcy process;•decisions from the Court related to the rejection of certain executory contracts, including certain sales, firm transportation and gathering contracts;•our ability to maintain compliance with debt covenants;•reductions to our borrowing base under the DIP Credit Agreement, which may begin on January 1, 2019 if we elect to extend the maturity of theDIP Credit Agreement;•our ability to fund, finance or repay indebtedness, including our ability to restructure our indebtedness during the Chapter 11 Cases;•limitations on our ability to incur certain types of indebtedness in accordance with our debt agreements;•requirements to provide certain vendors and other parties with letters of credit or cash deposits as a result of our credit quality, which reduce theamount of available borrowings under the DIP Credit Agreement;•the level of planned drilling activities;•the results of our ongoing drilling programs;•potential acquisitions and/or dispositions of oil and natural gas properties or other assets;•the integration of acquisitions of oil and natural gas properties or other assets;•our ability to effectively manage operating, general and administrative expenses and capital expenditure programs, specifically related to pricingpressures from key vendors utilized in our drilling, completion and operating activities;•reduced oil and natural gas revenues resulting from, among other things, depressed oil and natural gas prices and lower production fromreductions to our drilling and development activities;•our ability to mitigate commodity price volatility with commodity derivative financial instruments; and•the potential outcome of litigation.Recent events affecting LiquidityOur Liquidity and ability to maintain compliance with debt covenants have been negatively impacted by the prolonged depressed oil and natural gasprice environment, levels of indebtedness, and gathering, transportation and certain other commercial contracts. During 2017, we closed a series oftransactions that were intended to improve our Liquidity and capital structure. Despite our significant efforts to improve our financial condition, wecontinued to face increasing liquidity concerns. Due to liquidity constraints and restrictions and limitations on our ability to pay interest in cash, commonshares or additional indebtedness, we did not make our interest payment on the 1.75 Lien Term Loans that was due on December 20, 2017 and the interestpayment on the Second Lien Term Loans that was due on December 26, 2017. In anticipation of certain events of68Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.default related to compliance with financial covenants and failure to pay interest on certain debt instruments, we entered into agreements with certain holdersof the indebtedness under our EXCO Resources Credit Agreement, 1.5 Lien Notes, and 1.75 Lien Term Loans to forbear from exercising their rights andremedies as a result of an event of default under such debt instruments until January 15, 2018. Our Liquidity was $55.5 million as of December 31, 2017.On January 15, 2018, the Company and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. OnJanuary 22, 2018, we closed the DIP Credit Agreement, which includes an initial borrowing base of $250.0 million. The proceeds from the DIP CreditAgreement were used to refinance all obligations outstanding under the EXCO Resources Credit Agreement and will provide additional liquidity to fund ouroperations during the Chapter 11 process. Our capital budget for 2018 is limited to $125.0 million in order to preserve our Liquidity during the pendency ofthe bankruptcy process. We expect to incur significant costs associated with the bankruptcy process, including legal, financial and restructuring advisors tothe Company and certain of our creditors. Our ability to obtain confirmation of a successful plan of reorganization in timely manner is critical to ensuring ourLiquidity is sufficient during the bankruptcy process.The following table presents information relating to our Liquidity and outstanding debt as of December 31, 2017 and February 28, 2018:(in thousands) December 31,2017 February 28,2018DIP Credit Agreement $— $156,406EXCO Resources Credit Agreement 126,401 —1.5 Lien Notes 316,958 316,9581.75 Lien Term Loans 708,926 708,926Exchange Term Loan 17,246 17,2462018 Notes 131,345 131,3452022 Notes 70,169 70,169Total principal balance of debt $1,371,276 $1,401,050Net debt $1,316,408 $1,295,884Borrowing base $150,000 $250,000Unused borrowing base (1) $605 $69,600Cash (2) $54,868 $105,166Unused borrowing base plus cash $55,473 $174,766(1)Net of $23.0 million and $24.0 million in letters of credit as of December 31, 2017 and February 28, 2018, respectively.(2)Includes restricted cash of $15.3 million and $7.4 million at December 31, 2017 and February 28, 2018, respectively.As of January 15, 2018, we had approximately $1.4 billion in principal amount of indebtedness. The filing of the Chapter 11 Cases described aboveconstituted an event of default that accelerated our obligations under the following debt instruments:•EXCO Resources Credit Agreement;•1.5 Lien Notes;•1.75 Lien Term Loans;•2018 Notes; and•2022 Notes.These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall beimmediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of thecommencement of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments are subject to the applicable provisions ofthe Bankruptcy Code.The proceeds from the DIP Facilities were used to refinance all obligations under the EXCO Resources Credit Agreement and the EXCO ResourcesCredit Agreement was terminated. The DIP Credit Agreement contains certain financial covenants, including, but not limited to:•our cash (as defined in the DIP Credit Agreement) plus unused commitments under the DIP Credit Agreement cannot be less than of $20.0 million("Minimum Liquidity Test"); and69Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.•aggregate disbursements cannot exceed 120% of the aggregate disbursements (excluding professional fees incurred in the Chapter 11 Cases) setforth in the 13-week forecasts provided to the administrative agent of the DIP Credit Agreement. The testing period is based on the immediatelypreceding four-week period and is measured every two weeks. The 13-week forecast is provided to the administrative agent on a monthly basisand shall be consistent in all material respects with the applicable period covered by the 2018 budget that was previously delivered to theadministrative agent of the DIP Credit Agreement.The DIP Credit Agreement contains events of default, including: (i) conversion of the Chapter 11 Cases to cases under Chapter 7 of the BankruptcyCode and (ii) appointment of a trustee, examiner or receiver in the Chapter 11 Cases.The DIP Facilities will mature on the earliest of (a) 12 months from the initial borrowings on January 22, 2018, (b) the effective date of a plan ofreorganization in the Chapter 11 Cases and (c) the date of termination of all revolving commitments and/or the acceleration of the obligations under the DIPFacilities following an event of default. We have the option, subject to certain conditions, to extend the maturity of the DIP Facilities to the date that is 18months from the initial borrowing date. See further discussion of the DIP Credit Agreement in "Note 17. Subsequent events" in the Notes to our ConsolidatedFinancial Statements.Historical sources and uses of fundsNet increases (decreases) in cash are summarized as follows: Year Ended December 31,(in thousands) 2017 2016 2015Net cash provided by (used in) operating activities $54,411 $(414) $134,027Net cash used in investing activities (182,551) (55,009) (300,833)Net cash provided by (used in) financing activities 158,669 52,244 132,748Net increase (decrease) in cash $30,529 $(3,179) $(34,058)Operating activitiesThe primary factors impacting our cash flows from operating activities generally include: (i) levels of production from our oil and natural gasproperties, (ii) prices we receive from sales of oil and natural gas production, including settlement proceeds or payments related to our oil and natural gasderivatives, (iii) operating costs of our oil and natural gas properties, (iv) costs of our general and administrative activities and (v) interest expense. Our cashflows from operating activities have historically been impacted by fluctuations in oil and natural gas prices and our production volumes.For the year ended December 31, 2017, our net cash provided by operating activities was $54.4 million as compared to net cash used in operatingactivities of $0.4 million for the year ended December 31, 2016. The increase was primarily due to higher oil and natural gas prices, lower cash interestpayments and more favorable working capital conversions, partially offset by lower production and lower cash receipts on derivative contracts.For the year ended December 31, 2016, our net cash used in operating activities was $0.4 million as compared to net cash provided by operatingactivities of $134.0 million for the year ended December 31, 2015. The decrease was primarily attributable to lower revenues from decreased production andlower average oil and natural gas prices in 2016. In addition, the decrease was due to lower cash receipts on derivative contracts of $39.1 million for the yearended December 31, 2016 compared to $128.8 million for the year ended December 31, 2015. Working capital conversions contributed to a $35.3 milliondecrease in cash flows from operations for the year ended December 31, 2016, primarily due to the timing of collections of accounts receivable for oil andnatural gas sales, and costs incurred for our development program in late 2015 that were paid in early 2016.Investing activitiesOur investing activities consist primarily of drilling and development expenditures, acquisitions and divestitures. Future acquisitions are dependenton oil and natural gas prices, availability of attractive acreage and other oil and natural gas properties, acceptable rates of return, and availability of capital.For the year ended December 31, 2017, our net cash used in investing activities of $182.6 million primarily consisted of $147.0 million of drilling andcompletion activities in the North Louisiana region. In addition, we acquired oil and gas properties and undeveloped acreage in the North Louisiana regionfor $24.2 million.70Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.For the year ended December 31, 2016, our net cash used in investing activities was $55.0 million that primarily consisted of $79.4 million ofcompletion activities in the East Texas region and development activities in the North Louisiana region. This was partially offset by $14.3 million ofproceeds received primarily from the sale of certain non-core undeveloped acreage in South Texas and our interests in four producing wells and the sale ofour shallow conventional assets in Appalachia.For the year ended December 31, 2015, our net cash used in investing activities was $300.8 million primarily due to our drilling and completionactivities in the East Texas, North Louisiana and South Texas regions. The cash used in investing activities for the year ended December 31, 2015 included asignificant amount of expenditures related to the wells drilled in 2014.Financing activitiesFor the year ended December 31, 2017, our net cash provided by financing activities was $158.7 million. We received $295.5 million of net proceedsfrom the 1.5 Lien Notes, which we used to repay borrowings under the EXCO Resources Credit Agreement in the amount of $265.6 million. We subsequentlyhad net borrowings of $163.4 million under the EXCO Resources Credit Agreement, which exhausted substantially all of our remaining unused commitmentsunder the EXCO Resources Credit Agreement. In addition, we made payments of $22.1 million related to debt restructuring activities during the first quarterof 2017, and we made payments of $11.6 million on the Exchange Term Loan, which reduced its carrying value.For the year ended December 31, 2016, our net cash provided by financing activities was $52.2 million primarily due to $161.1 million in netborrowings under the EXCO Resources Credit Agreement partially offset by payments of $50.7 million on the Exchange Term Loan, which reduced itscarrying value, and an aggregate of $53.3 million of cash payments used to repurchase a portion of our 2018 Notes and 2022 Notes. On March 29, 2016, weborrowed our remaining unused commitments of $232.4 million under the EXCO Resources Credit Agreement to secure our Liquidity. Prior to thecompletion of the borrowing base redetermination process on March 29, 2016, we repaid the entire $232.4 million. The borrowing and subsequent repaymentboth occurred on the same day.For the year ended December 31, 2015, our net cash provided by financing activities was $132.7 million primarily due to $300.0 million of proceedsreceived from the Fairfax Term Loan and $165.0 million in borrowings under the EXCO Resources Credit Agreement. We used the proceeds from the FairfaxTerm Loan to repay the outstanding indebtedness under the EXCO Resources Credit Agreement. The issuance of the Exchange Term Loan and the relatedretirements of the 2018 and 2022 Notes were conducted simultaneously with the same creditors and did not impact our cash flows from financing activities.In addition, we used cash to pay $20.9 million of deferred financing costs primarily related to recent debt restructuring activities, repurchase a portion of the2018 Notes for $12.0 million and a cash payment of $8.8 million that reduced the carrying value of the Exchange Term Loan.Capital expendituresDuring 2017, our capital expenditures, including oil and natural gas property acquisitions, totaled $189.9 million, of which $147.9 million wasprimarily related to the development of the Haynesville shale and the appraisal of the Bossier shale in North Louisiana. Our development program in NorthLouisiana during 2017 included drilling 29 gross (17.9 net) operated wells and turning-to-sales 12 gross (8.4 net) operated wells. The development programin this region included a significant amount of capital expenditures on wells that will be completed in subsequent years. As of December 31, 2017, we had 17gross (9.3 net) operated wells in North Louisiana that were drilled and waiting on completion or in various stages of the completion process. In addition, werestarted development activities in South Texas focused on the Eagle Ford shale in late 2017. This included drilling 2 gross (1.6 net) operated wells during2017. Our oil and natural gas property acquisitions during 2017 primarily included incremental interests in certain oil and natural gas properties that weoperate and undeveloped acreage in the North Louisiana region.During 2016, our capital expenditures, including oil and natural gas property acquisitions, totaled $79.4 million, of which $62.3 million was related todrilling and completion activities. Our development program during 2016 included an operated drilling rig for a portion of the year focused on theHaynesville shale in North Louisiana, to drill and complete 6 gross (5.2 net) operated wells. The wells drilled in 2016 featured a modified Haynesville shalewell design which included enhanced completion methods, including the use of more proppant and longer laterals. We also completed 8 gross (3.6 net)operated wells in the Haynesville and Bossier shales in the Shelby area of East Texas.During 2015, our capital expenditures, including oil and natural gas property acquisitions, totaled $284.8 million, of which $228.5 million was relatedto drilling and development activities. Our development program during 2015 focused71Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.primarily on the Haynesville and Bossier shales in the Shelby area of East Texas. Our development activities in North Louisiana during 2015 includedlimited drilling as well as completion activities. Our capital expenditures in the South Texas region focused on the development of the Eagle Ford shale andthe Buda formation, as well as the leasing of acreage in Zavala County, Texas. As a result of the decline in oil prices, we suspended our drilling in the SouthTexas region in the fourth quarter of 2015. We drilled an appraisal well in the Marcellus shale in Northeast Pennsylvania, which will be turned-to-sales in2018 upon construction of a gathering line.The following table presents our capital expenditures for the years ended December 31, 2017, 2016 and 2015. Year Ended December 31,(in thousands) 2017 2016 2015Capital expenditures: Lease purchases and seismic $5,854 $767 $13,364Development capital expenditures 147,861 62,328 228,545Field operations, gathering and water pipelines 220 667 6,672Corporate and other 11,483 14,637 28,602Total capital expenditures excluding oil and natural gas property acquisitions 165,418 78,399 277,183Oil and natural gas property acquisitions 24,465 1,031 7,608Total capital expenditures including oil and natural gas property acquisitions $189,883 $79,430 $284,7912018 Capital BudgetOur capital budget for 2018 includes $124.0 million for drilling and completion activities focused on the Haynesville and Eagle Ford shales. Thedevelopment of the Haynesville shale in North Louisiana includes drilling 1 gross (0.7 net) operated well and the completion of 11 gross (6.7 net) operatedwells. The completion activities in North Louisiana primarily include wells drilled in prior year. Our development program for the Eagle Ford shale includesthe drilling of 10 gross (8.0 net) operated wells and completion of 12 gross (9.6 net) operated wells that will preserve the value of certain acreage withleasehold obligations. Our drilling and completion activities include $21.0 million to participate in the development of non-operated wells. In addition, weplan to spend a limited amount of capital on maintenance and leasehold costs. The capital expenditures associated with the development plans are highlyconcentrated in the first half of 2018. The 2018 capital budget is currently allocated as follows:(in thousands) 2018 CapitalBudgetLease purchases and seismic $4,000Development capital expenditures 113,000Field operations, gathering and water pipelines 3,000Corporate and other 4,000Total capital expenditures $124,000Derivative financial instrumentsOur production is generally sold at prevailing market prices. We have historically entered into oil and natural gas derivative contracts for a portion ofour production to mitigate the impact of commodity price fluctuations and achieve a more predictable cash flow associated with our operations. Thesetransactions limit our exposure to declines in prices, but also limit the benefits we would realize if oil and natural gas prices increase.As of December 31, 2017, we had derivative financial instruments in place for the volumes and prices shown below: NYMEX gas volume - Bbtu Weighted average contract priceper Mmbtu NYMEX oil volume - Mbbl Weighted average contractprice per BblSwaps: 2018 3,650 $3.15 — —In January 2018, the counterparty to our remaining swap contracts early terminated the outstanding contracts effective January 31, 2018. We receivedproceeds of $0.5 million for the settlement of these contracts in February 2018. As a result, we72Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.no longer have any derivative financial instruments to mitigate the impact of fluctuations in the market prices of oil and natural gas. Historically, oil andnatural gas prices have been volatile and are dependent on factors outside of our control. Reductions in the market price of oil and natural gas prices in thefuture may adversely affect our revenues as well as our ability to fund our operations and maintain compliance with debt covenants. See further details on ourderivative financial instruments in "Note 4. Derivative financial instruments" and "Note 6. Fair value measurements" in the Notes to our ConsolidatedFinancial Statements.Off-balance sheet arrangementsAs of December 31, 2017, we had no arrangements or any guarantees of off-balance sheet debt to third parties.Contractual obligations and commercial commitmentsThe following table presents our contractual obligations and commercial commitments as of December 31, 2017 and does not include those of ourequity method investments. Our remaining obligations under many of these obligations and commitments will be materially impacted by the outcome of ourChapter 11 proceedings. See "Note 17. Subsequent events" in the Notes to our Consolidated Financial Statements for additional information. Payments due by period(in thousands) Less than oneyear One to threeyears Three to fiveyears More than fiveyears TotalEXCO Resources Credit Agreement (1) $126,401 $— $— $— $126,4011.5 Lien Notes (2) — — 316,958 — 316,9581.75 Lien Term Loans (3) — 708,926 — — 708,926Exchange Term Loan (4) — 17,246 — — 17,246Senior Notes (5) 131,576 — 70,169 201,745Gathering and firm transportation services (6) 87,621 94,004 66,612 94,443 342,680Other fixed commitments (7) 3,222 4,364 1,601 — 9,187Drilling contracts (8) 1,138 — — — 1,138Operating leases and other 3,760 4,771 36 — 8,567Total contractual obligations $353,718 $829,311 $455,376 $94,443 $1,732,848(1)The EXCO Resources Credit Agreement matures on July 31, 2018. The interest rate grid on the revolving credit facility of the EXCO Resources Credit Agreement rangesfrom LIBOR plus 225 bps to 325 bps (or ABR plus 125 bps to 225 bps), depending on the percentages of drawn balances to the borrowing base. On January 22, 2018,we utilized the proceeds from the DIP Facilities to refinance all obligations under the EXCO Resources Credit Agreement.(2)The 1.5 Lien Notes mature on March 20, 2022. The 1.5 Lien Notes bear interest at a cash interest rate of 8% per annum, or, if we elect to make interest payments on the1.5 Lien Notes by issuing common shares or additional 1.5 Lien Notes, at an interest rate of 11% per annum. Based on the outstanding principal balance as of December31, 2017, the annual interest obligation is $25.4 million if paid in cash or $34.9 million if paid in-kind with additional 1.5 Lien Notes or common shares.(3)The 1.75 Lien Term Loans mature on October 26, 2020. The 1.75 Lien Term Loans bear interest at a cash interest rate of 12.5% per annum, or, if we elect to make interestpayments on the 1.75 Lien Term Loans by issuing common shares additional 1.75 Lien Term Loans, at an interest rate of 15% per annum. Based on the outstandingprincipal balance as of December 31, 2017, the annual interest obligation is $88.6 million if paid in cash or $106.3 million if paid in-kind with additional 1.75 Lien TermLoans or common shares.(4)The Exchange Term Loan matures on October 26, 2020. Based on the outstanding principal balance as of December 31, 2017, the annual interest obligation on theExchange Term Loan is $2.2 million based on the interest rate of 12.5% per annum.(5)The 2018 Notes are due on September 15, 2018 and the 2022 Notes are due on April 15, 2022. Based on the outstanding principal balance at December 31, 2016, theannual interest obligation on the 2018 Notes and 2022 Notes is $7.0 million and $6.0 million, respectively.(6)Gathering and firm transportation services reflect contracts whereby EXCO commits to transport a minimum quantity of natural gas on a gatherer's system or a shipper'spipeline. Whether or not EXCO delivers the minimum quantity, we pay the fees as if the quantities were delivered. These expenses represent our gross commitmentsunder these contracts and a portion of these costs will be incurred by working interest and other owners. As described in "Note 2. Summary of significant accountingpolicies" in the Notes to our Consolidated Financial Statements, we report these costs as gathering and transportation expenses or as a reduction in total sales pricereceived from the purchaser. In addition, our variable rate gathering and firm transportation contracts do not have a minimum volume commitment and are not included inthe table above. As such, our gathering and firm transportation services73Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.presented in the table above may not be representative of the amounts reported as gathering and transportation expenses in our Consolidated Financial Statements.During 2017, we accelerated the remaining costs under a firm transportation agreement as a result of our default. As of December 31, 2017, the unpaid amounts andremaining charges under this agreement were $67.3 million and are recorded as a liability in "Revenue and royalties payable" in our Consolidated Balance Sheet.Therefore, the amounts payable related to this agreement were excluded from the table above. In addition, we are in litigation related to certain other sales andtransportation contracts. The commitments related to the contracts currently in litigation are included in the table above and the termination of these contracts will not bereflected in our financial results until the litigation is resolved and it is deemed to be realized in accordance with GAAP. See "Note 8. Commitments and contingencies" inthe Notes to our Consolidated Financial Statements for additional information.(7)Other fixed commitments are primarily related to minimum sales commitments under marketing contracts.(8)Drilling contracts represent the contractual rate for our operated rigs through the term of the contracts as of December 31, 2017. The actual drilling costs under thesecontracts will be incurred by working interest owners in the development of the related properties.Item 7A. Quantitative and Qualitative Disclosures About Market RiskSome of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-lookingquantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adversechanges in oil and natural gas prices, interest rates charged on borrowings and earned on cash equivalent investments, and adverse changes in the marketvalue of marketable securities. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possiblelosses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitiveinstruments were entered into for hedging and investment purposes, not for trading purposes.Commodity price riskOur most significant market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by theprevailing worldwide price for crude oil and spot market prices for natural gas. Pricing for oil and natural gas production is volatile. For the year endedDecember 31, 2017, a $1.00 decrease in the average commodity price per Mcfe would have resulted in a decrease in oil and natural gas revenues, excludingthe impact of commodity derivative financial instruments, of approximately $87.1 million.We have historically entered into derivative financial instruments to manage our exposure to commodity price fluctuations, protect our returns oninvestments, and achieve a more predictable cash flow in connection with our financing activities and borrowings related to these activities. Thesetransactions limit exposure to declines in prices, but also limit the benefits we would realize if oil and natural gas prices increase. Subsequent to the earlytermination of a natural gas swap contract in January 2018, our future production is not covered by any commodity derivative financial instruments. Duringthe Chapter 11 proceedings, our ability to enter into new commodity derivative contracts covering additional estimated future production is limited underthe DIP Credit Agreement. We are only permitted to enter into additional commodity derivative contracts with lenders under the DIP Credit Agreement. As aresult, we may not be able to enter into additional commodity derivative contracts covering our production in future periods on favorable terms or at all. If wecannot or choose not to enter into commodity derivative contracts in the future, we could be more affected by changes in commodity prices. Our inability tohedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial conditionand results of operations.Interest rate riskAt December 31, 2017, our exposure to interest rate changes related primarily to borrowings under the EXCO Resources Credit Agreement. The interestrates per annum on the 2018 Notes, 2022 Notes and Second Lien Term Loans are fixed at 7.5%, 8.5% and 12.5%, respectively. The 1.5 Lien Notes bearinterest at a cash interest rate of 8% per annum, or, if we elect to make interest payments on the 1.5 Lien Notes with our common shares or, in certaincircumstances, by issuing additional 1.5 Lien Notes, at an interest rate of 11% per annum. The 1.75 Lien Term Loans bear interest at a cash rate of 12.5% perannum, or, if we elect to pay interest on the 1.75 Lien Term Loans with our common shares or, in certain circumstances, by issuing additional 1.75 Lien TermLoans, at an interest rate of 15.0% per annum.On January 22, 2018, we closed the DIP Credit Agreement and utilized the proceeds to refinance all obligations outstanding under the EXCOResources Credit Agreement. Interest is payable on borrowings under the DIP Credit Agreement based on an adjusted LIBOR plus 4.00% per annum. AtFebruary 28, 2018, we had approximately $156.4 million in outstanding borrowings under the DIP Credit Agreement. A 1.0% increase in interest rates (100bps) based on the variable74Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.borrowings as of February 28, 2018 would result in an increase in our interest expense of approximately $1.6 million per year. The interest we pay on theseborrowings is set periodically based upon market rates.Equity price risk Our exposure to changes in our common share price primarily relate to the 2017 Warrants. We account for the 2017 Warrants as derivative instrumentsand record the warrants as a non-current liability at fair value, with the change in fair value recognized in earnings. The 2017 Warrants will be measured atfair value on a recurring basis until the underlying common share warrants are exercised or the date of expiration. The 2017 Warrants had a fair value of $2.0million on December 31, 2017. As of December 31, 2017, a 10% increase in the price of our common shares would have increased the fair value of theliability related to the 2017 Warrants by approximately $0.3 million. As discussed in "Item 1A. Risk Factors", we believe it is highly likely that our existingcommon shares will be canceled at the conclusion of our Chapter 11 proceedings, and the holders of our existing common shares will be entitled to a limitedrecovery, if any.75Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Item 8.Financial Statements and Supplementary DataEXCO Resources, Inc.Index to Consolidated Financial Statements Management's Report on Internal Control Over Financial Reporting77 Reports of Independent Registered Public Accounting Firm78 Consolidated Balance Sheets at December 31, 2017 and 201680 Consolidated Statements of Operations for the years ended December 31, 2017, 2016, and 201581 Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016, and 201582 Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31, 2017, 2016, and 201583 Notes to Consolidated Financial Statements8476Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Management's Report on Internal Control Over Financial ReportingTo the Board of Directors and Shareholders ofEXCO Resources, Inc.: Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under theSecurities Exchange Act of 1934, as amended). Our internal control over financial reporting is designed to provide reasonable assurance to management andour Board of Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal controlover financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonableassurance with respect to financial statement preparation and presentation. Management assessed the effectiveness of our internal control over financialreporting as of December 31, 2017. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of theTreadway Commission ("COSO") in Internal Control-Integrated Framework (2013). Based on management's assessment, management believes that, as ofDecember 31, 2017, our internal control over financial reporting was effective based on those criteria. The effectiveness of EXCO Resources, Inc.'s internal control over financial reporting as of December 31, 2017 has been audited by KPMG LLP, anindependent registered public accounting firm, as stated in their report which appears herein.By:/s/ Harold L. Hickey By:/s/ Tyler S. FarquharsonTitle:Chief Executive Officer and President Title:Vice President, Chief Financial Officer and Treasurer Dallas, Texas March 15, 2018 77Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Report of Independent Registered Public Accounting FirmThe Shareholders and Board of DirectorsEXCO Resources, Inc.:Opinion on the Consolidated Financial StatementsWe have audited the accompanying consolidated balance sheets of EXCO Resources, Inc. and subsidiaries (the Company) as of December 31, 2017 and2016, the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years in the three-year period endedDecember 31, 2017, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements presentfairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows foreach of the years in the three-year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’sinternal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued bythe Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 15, 2018 expressed an unqualified opinion on theeffectiveness of the Company’s internal control over financial reporting.Going ConcernThe accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in note 1 tothe consolidated financial statements, the Company filed a voluntary petition for reorganization under Chapter 11 of the United States Bankruptcy Code onJanuary 15, 2018, which raises substantial doubt about the Company’s ability to continue as a going concern. Management's plans in regard to this matter arealso described in note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.Basis for OpinionThese consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on theseconsolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board(United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and theapplicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonableassurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performingprocedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures thatrespond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financialstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating theoverall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion./s/ KPMG LLPWe have served as the Company’s auditor since 2006Dallas, TexasMarch 15, 201878Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Report of Independent Registered Public Accounting FirmThe Shareholders and Board of DirectorsEXCO Resources, Inc.:Opinion on Internal Control Over Financial ReportingWe have audited EXCO Resources, Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2017, based on criteriaestablished in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In ouropinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteriaestablished in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidatedbalance sheets of the Company as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in shareholders’ equity, andcash flows for each of the years in the three-year period ended December 31, 2017, and the related notes, (collectively, the consolidated financial statements)and our report dated March 15, 2018 expressed an unqualified opinion on those consolidated financial statements.Basis for OpinionThe Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness ofinternal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Ourresponsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firmregistered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and theapplicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonableassurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financialreporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing andevaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures aswe considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.Definition and Limitations of Internal Control Over Financial ReportingA company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reportingand the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal controlover financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are beingmade only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention ortimely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancewith the policies or procedures may deteriorate./s/ KPMG LLPDallas, TexasMarch 15, 201879Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. EXCO RESOURCES, INC.CONSOLIDATED BALANCE SHEETS(in thousands) December 31, 2017 December 31, 2016 Assets Current assets: Cash and cash equivalents $39,597 $9,068Restricted cash 15,271 11,150Accounts receivable, net: Oil and natural gas 55,692 52,674Joint interest 30,570 25,905Other 1,976 3,813Derivative financial instruments - commodity derivatives 1,150 —Other current assets 23,574 8,007Total current assets 167,830 110,617Equity investments 14,181 24,365Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties and development costs not being amortized 118,652 97,080Proved developed and undeveloped oil and natural gas properties 3,107,566 2,939,923Accumulated depletion (2,752,311) (2,702,245)Oil and natural gas properties, net 473,907 334,758Other property and equipment, net and other non-current assets 21,274 23,661Deferred financing costs, net — 4,376Derivative financial instruments — 482Goodwill 163,155 163,155Total assets $840,347 $661,414Liabilities and shareholders’ equity Current liabilities: Accounts payable and accrued liabilities $68,277 $54,762Revenues and royalties payable 207,956 120,845Accrued interest payable 27,637 4,701Current portion of asset retirement obligations 600 344Income taxes payable — —Derivative financial instruments - commodity derivatives — 27,711Current maturities of long-term debt 1,362,500 50,000Total current liabilities 1,666,970 258,363Long-term debt — 1,258,538Deferred income taxes 4,518 2,802Derivative financial instruments - commodity derivatives — 464Derivative financial instruments - common share warrants 1,950 —Asset retirement obligations and other long-term liabilities 13,108 13,153Commitments and contingencies — —Shareholders’ equity: Common shares, $0.001 par value; 260,000,000 authorized shares; 21,670,186 shares issued and 21,630,541 sharesoutstanding at December 31, 2017; 18,915,952 shares issued and 18,876,307 shares outstanding at December 31, 2016 22 19Additional paid-in capital 3,539,422 3,538,080Accumulated deficit (4,378,011) (4,402,373)Treasury shares, at cost; 39,645 at December 31, 2017 and 2016 (7,632) (7,632)Total shareholders’ equity (846,199) (871,906)Total liabilities and shareholders’ equity $840,347 $661,414See accompanying notes.80Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO RESOURCES, INC.CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31,(in thousands, except per share data) 2017 2016 2015Revenues: Oil $57,693 $67,317 $102,787Natural gas 201,137 181,332 226,471Purchased natural gas and marketing 24,816 22,352 26,442Total revenues 283,646 271,001 355,700Costs and expenses: Oil and natural gas operating costs 35,011 34,609 53,903Production and ad valorem taxes 13,131 15,380 22,630Gathering and transportation 111,427 106,460 99,321Purchased natural gas 23,400 23,557 27,369Depletion, depreciation and amortization 51,040 75,982 215,426Impairment of oil and natural gas properties — 160,813 1,215,370Accretion of discount on asset retirement obligations 874 2,210 2,277General and administrative 30,165 48,700 58,818Other operating items 59,154 24,239 461Total costs and expenses 324,202 491,950 1,695,575Operating loss (40,556) (220,949) (1,339,875)Other income (expense): Interest expense, net (108,175) (70,438) (106,082)Gain (loss) on derivative financial instruments - commodity derivatives 24,732 (34,137) 75,869Gain on derivative financial instruments - common share warrants 159,190 — —Gain (loss) on restructuring and extinguishment of debt (6,380) 119,457 193,276Other income 31 43 122Equity loss (4,184) (16,432) (15,691)Total other income (expense) 65,214 (1,507) 147,494Income (loss) before income taxes 24,658 (222,456) (1,192,381)Income tax expense 296 2,802 —Net income (loss) $24,362 $(225,258) $(1,192,381)Earnings (loss) per common share: Basic: Net income (loss) $1.14 $(12.09) $(65.37)Weighted average common shares outstanding 21,288 18,630 18,241Diluted: Net income (loss) $1.14 $(12.09) $(65.37)Weighted average common shares and common share equivalents outstanding 21,288 18,630 18,241See accompanying notes.81Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO RESOURCES, INC.CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31,(in thousands) 2017 2016 2015Operating Activities: Net income (loss) $24,362 $(225,258) $(1,192,381)Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Deferred income tax expense 1,716 2,802 —Depletion, depreciation and amortization 51,040 75,982 215,426Equity-based compensation (11,430) 14,778 7,198Accretion of discount on asset retirement obligations 874 2,210 2,277Impairment of oil and natural gas properties — 160,813 1,215,370Loss from equity investments 4,184 16,432 15,691Proceeds from equity investments 4,452 — (Gain) loss on derivative financial instruments - commodity derivatives (24,732) 34,137 (75,869)Cash receipts (payments) of commodity derivative financial instruments (4,111) 39,149 128,800Gain on derivative financial instruments - common share warrants (159,190) — —Amortization of deferred financing costs and discount on debt issuance 26,960 9,256 16,994Paid in-kind interest expense 59,464 — —Other non-operating items 2,006 24,073 (32)Gain (loss) on restructuring and extinguishment of debt 6,380 (119,457) (193,276)Effect of changes in: Restricted cash with related party — 2,100 (2,100)Accounts receivable (7,160) (19,763) 88,610Other current assets (12,498) (1,716) 434Accounts payable and other current liabilities 92,094 (15,952) (93,115)Net cash provided by (used in) operating activities 54,411 (414) 134,027Investing Activities: Additions to oil and natural gas properties, gathering assets and equipment (147,016) (79,393) (317,590)Property acquisitions (24,151) (1,032) (7,608)Proceeds from disposition of property and equipment 350 14,349 7,397Restricted cash (4,121) 7,970 4,850Net changes in advances to joint ventures (9,161) 3,097 10,663Equity investments and other 1,548 — 1,455Net cash used in investing activities (182,551) (55,009) (300,833)Financing Activities: Borrowings under EXCO Resources Credit Agreement 163,401 404,897 165,000Repayments under EXCO Resources Credit Agreement (265,592) (243,797) (300,000)Proceeds received from issuance of 1.5 Lien Notes, net 295,530 — —Repurchases of senior unsecured notes — (53,298) (12,008)Proceeds received from issuance of Fairfax Term Loan — — 300,000Payments on Exchange Term Loan (11,602) (50,695) (8,827)Proceeds from issuance of common shares, net — — 9,693Payments of common share dividends (6) (91) (164)Deferred financing costs and other (23,062) (4,772) (20,946)Net cash provided by (used in) financing activities 158,669 52,244 132,748Net increase (decrease) in cash 30,529 (3,179) (34,058)Cash at beginning of period 9,068 12,247 46,305Cash at end of period $39,597 $9,068 $12,247Supplemental Cash Flow Information: Cash interest payments $27,786 $68,134 $117,463Income tax payments — — —Supplemental non-cash investing and financing activities: Capitalized equity-based compensation $1,000 $752 $3,428Capitalized interest 6,440 5,213 12,040See accompanying notes.Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.82Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO RESOURCES, INC.CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY Common Shares Treasury Shares Additional paid-incapital Accumulateddeficit Totalshareholders’equity(in thousands) Shares Amount Shares Amount Balance at December 31, 2014 18,301 $18 (39) $(7,615) $3,502,461 $(2,984,860) $510,004Issuance of common shares 392 1 — — 9,843 — 9,844Equity-based compensation — — — — 10,106 — 10,106Restricted shares issued, net of cancellations 227 — — — — — —Common share dividends — — — — — 121 121Treasury share repurchases — — (1) (17) — — (17)Net loss — — — — — (1,192,381) (1,192,381)Balance at December 31, 2015 18,920 $19 (40) $(7,632) $3,522,410 $(4,177,120) $(662,323)Issuance of common shares 16 — — — — — —Equity-based compensation — — — — 15,662 — 15,662Restricted shares issued, net of cancellations (20) — — — 8 — 8Common share dividends — — — — — 5 5Net loss — — — — — (225,258) (225,258)Balance at December 31, 2016 18,916 $19 (40) $(7,632) $3,538,080 $(4,402,373) $(871,906)Issuance of common shares 2,746 3 — — 11,395 — 11,398Equity-based compensation — — — — (10,053) — (10,053)Restricted shares issued, net of cancellations 8 — — — — — —Net income — — — — — 24,362 24,362Balance at December 31, 2017 21,670 $22 (40) $(7,632) $3,539,422 $(4,378,011) $(846,199)See accompanying notes.83Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO RESOURCES, INC.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS1.Organization and basis of presentation Unless the context requires otherwise, references in this Annual Report on Form 10-K to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and“our” are to EXCO Resources, Inc. and its consolidated subsidiaries. We are an independent oil and natural gas company engaged in the exploration, exploitation, acquisition, development and production of onshoreU.S. oil and natural gas properties with a focus on shale resource plays. Our principal operations are conducted in certain key U.S. oil and natural gas areasincluding Texas, Louisiana and the Appalachia region. The following is a brief discussion of our producing regions.•East Texas and North LouisianaThe East Texas and North Louisiana regions are primarily comprised of our Haynesville and Bossier shale assets. We have a joint venture with awholly owned subsidiary of Royal Dutch Shell, plc, ("Shell") covering an undivided 50% interest in the majority of our Haynesville and Bossiershale assets in East Texas and North Louisiana. The East Texas and North Louisiana regions also include certain assets outside of the joint venturein the Haynesville and Bossier shales. We serve as the operator for most of our properties in the East Texas and North Louisiana regions.•South TexasThe South Texas region is primarily comprised of our Eagle Ford shale assets. We serve as the operator for most of our properties in the South Texasregion.•AppalachiaThe Appalachia region is primarily comprised of our Marcellus shale assets. We had a joint venture with Shell covering our Marcellus shale andother assets in the Appalachia region ("Appalachia JV"). EXCO and Shell each owned an undivided 50% interest in the Appalachia JV and a 49.75%working interest in the Appalachia JV's properties. The remaining 0.5% working interest is held by a jointly owned operating entity ("OPCO") thatoperates the Appalachia JV's properties. We owned a 50% interest in OPCO. On February 27, 2018, we closed a settlement agreement with asubsidiary of Shell to resolve arbitration regarding our right to participate in an area of mutual interest in the Appalachia region ("Appalachia JVSettlement"). As a result of the Appalachia JV Settlement, we acquired Shell's interests in the Appalachia JV and OPCO. See further discussion of thissettlement as part of "Note 17. Subsequent events".The accompanying Consolidated Balance Sheets as of December 31, 2017 and 2016, Consolidated Statements of Operations, Consolidated Statementsof Cash Flows and Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2017, 2016 and 2015 are for EXCO and itssubsidiaries. The Consolidated Financial Statements and related footnotes are presented in accordance with generally accepted accounting principles in theUnited States ("GAAP"). Certain reclassifications have been made to prior period information to conform to current period presentation.Reverse share splitOn June 2, 2017, we filed a certificate of amendment to our Amended and Restated Certificate of Formation to reduce the number of authorizedcommon shares from 780,000,000 to 260,000,000 and effect a 1-for-15 reverse share split. The reverse share split became effective after the market closed onJune 12, 2017. The par value of the common shares remained unchanged at $0.001 per share, which required retrospective reclassification from commonshares to additional paid-in capital within the shareholders' equity section of our consolidated balance sheets. Shareholders' equity and all share data,including treasury shares, and per share data presented herein have been retrospectively adjusted to reflect the impact of the decrease in authorized shares andthe reverse share split, as appropriate.Chapter 11 Cases and Going Concern AssessmentOn January 15, 2018, the Company and certain of its subsidiaries, including EXCO Services, Inc., EXCO Partners GP, LLC, EXCO GP Partners OLP,LP, EXCO Partners OLP GP, LLC, EXCO Operating Company, LP, EXCO Midcontinent MLP, LLC, EXCO Holding (PA), Inc., EXCO Production Company(PA), LLC, EXCO Resources (XA), LLC, EXCO Production Company (WV), LLC, EXCO Land Company, LLC, EXCO Holding MLP, Inc., Raider Marketing,LP, Raider Marketing GP, LLC (collectively, the “Filing Subsidiaries” and, together with the Company, the “Debtors”), filed voluntary petitions for relief84Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.under Chapter 11 of the United States Bankruptcy Code (“Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas(“Court”). The Chapter 11 cases are being jointly administered under the caption In Re EXCO Resources, Inc., Case No. 18-30155 (MI) ("Chapter 11 Cases").The Court granted all of the first day motions filed by the Debtors that were designed primarily to minimize the impact of the Chapter 11 proceedings on ouroperations, customers and employees. We will continue to operate our businesses as “debtors in possession” under the jurisdiction of the Court and inaccordance with the applicable provisions of the Bankruptcy Code and orders of the Court. We expect to continue our operations without interruption duringthe pendency of the Chapter 11 proceedings.For the duration of the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to risks anduncertainties associated with Chapter 11 proceedings described in "Item 1A. Risk Factors”. As a result of these risks and uncertainties, our assets, liabilities,shareholders' equity, officers and/or directors could be significantly different following the conclusion of the Chapter 11 Cases, and the description of ouroperations, properties and capital plans included in this annual report may not accurately reflect our operations, properties and capital plans following theChapter 11 Cases. See further discussion of the Chapter 11 proceedings in "Note 17. Subsequent events".We were not able to reach an agreement with our creditors for a plan of reorganization prior to commencement of the Chapter 11 Cases. Therefore, theoutcome of our Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors outside of our control, including actions of theCourt and our creditors. The significant risks and uncertainties related to our Liquidity and Chapter 11 proceedings described above raise substantial doubtabout our ability to continue as a going concern. These Consolidated Financial Statements have been prepared on a going concern basis, which contemplatesthe realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. The accompanying Consolidated FinancialStatements do not include any adjustments to reflect the possible future effects of this uncertainty on the recoverability or classification of recorded assetamounts or the amounts or classification of liabilities.2.Summary of significant accounting policiesPrinciples of consolidationWe consolidate all of our subsidiaries in the accompanying Consolidated Balance Sheets as of December 31, 2017 and 2016 and the ConsolidatedStatements of Operations, Consolidated Statements of Cash Flows and Changes in Shareholders' Equity for the years ended December 31, 2017, 2016 and2015. Investments in unconsolidated affiliates in which we are able to exercise significant influence are accounted for using the equity method. We use thecost method of accounting for investments in unconsolidated affiliates in which we are not able to exercise significant influence. All intercompanytransactions and accounts have been eliminated.Management estimatesIn preparing the Consolidated Financial Statements in conformity with GAAP, we are required to make estimates and assumptions that affect thereported amounts of assets, liabilities, revenues and expenses during the reporting periods. The more significant estimates pertain to proved oil and naturalgas reserve volumes, future development costs, asset retirement obligations, equity-based compensation, estimates relating to oil and natural gas revenuesand expenses, accrued liabilities, the fair market value of assets and liabilities acquired in business combinations, derivatives and goodwill. Actual resultsmay differ from management's estimates.Cash equivalentsWe consider all highly liquid investments with maturities of three months or less when purchased, to be cash equivalents.Restricted cashThe restricted cash on our balance sheet is principally comprised of our share of an evergreen escrow account with Shell that is used to fund our shareof development operations in East Texas and North Louisiana. Funds held in this escrow account are restricted and can be used primarily for drilling andoperations in East Texas and North Louisiana.Concentration of credit risk and accounts receivableFinancial instruments that potentially subject us to a concentration of credit risk consist principally of cash, trade receivables and our derivativefinancial instruments. We place our cash with financial institutions which we believe have85Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.sufficient credit quality to minimize risk of loss. We sell oil and natural gas to various customers. In addition, we participate with other parties in the drilling,completion and operation of oil and natural gas wells. The majority of our accounts receivable are due from either purchasers of oil or natural gas orparticipants in oil and natural gas wells for which we serve as the operator. We have the right to offset future revenues against unpaid charges related to wellswhich we operate. Oil and natural gas receivables are generally uncollateralized. The allowance for doubtful accounts was immaterial at both December 31,2017 and 2016. We place our derivative financial instruments with financial institutions that we believe have high credit ratings. To mitigate our risk of lossdue to default, we have entered into master netting agreements with our counterparties on our derivative financial instruments that allow us to offset our assetposition with our liability position in the event of a default by the counterparty.For the years ended December 31, 2017, 2016 and 2015, sales to BG Energy Merchants LLC, and subsequently a subsidiary of Shell accounted forapproximately 32%, 24% and 20%, respectively, of total consolidated revenues. BG Energy Merchants LLC was a subsidiary of BG Group, plc ("BG Group")until the acquisition of BG Group by Shell in early 2016. In January 2018, we discontinued the sale of natural gas to Shell in the East Texas and NorthLouisiana regions as a result of litigation regarding certain natural gas sales contracts. See further discussion in "Item 3. Legal proceedings" and in "Note 8.Commitments and contingencies". We have not experienced any interruptions or negative impact to our natural gas sales prices as a result the discontinuanceof sales to Shell in these regions. For the years ended December 31, 2017, 2016 and 2015, Chesapeake Energy Marketing Inc. accounted for approximately17%, 32%, and 38% respectively, of total consolidated revenues. Chesapeake Energy Marketing Inc. is a subsidiary of Chesapeake Energy Corporation("Chesapeake").Derivative financial instrumentsOur derivative financial instruments are comprised of commodity derivative contracts and the 2017 Warrants (as defined in "Note 4. Derivativefinancial instruments"). We use commodity derivative financial instruments to mitigate the impacts of commodity price fluctuations, protect our returns oninvestments and achieve a more predictable cash flow. FASB ASC 815, Derivatives and Hedging, ("ASC 815"), requires that every derivative instrument(including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at itsestimated fair value. ASC 815 requires that changes in the derivative's estimated fair value be recognized in earnings unless specific hedge accountingcriteria are met, or exemptions for normal purchases and normal sales as permitted by ASC 815 exist. We do not designate our derivative financialinstruments as hedging instruments and, as a result, recognize the change in a derivative's estimated fair value in earnings as a component of other income orexpense. Our derivative financial instruments are not held for trading purposes.Oil and natural gas propertiesThe accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives: the full costmethod or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitationand development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unprovedproperties, collectively, the full cost pool. Our unproved property costs, which include unproved oil and natural gas properties, properties under developmentand major development projects, collectively totaled $118.7 million and $97.1 million as of December 31, 2017 and 2016, respectively, and are not subjectto depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs toproved properties as a result of extension or discoveries from drilling operations or determination that no Proved Reserves are attributable to such costs. Indetermining whether such costs should be impaired or transferred, we evaluate lease expiration dates, recent drilling results, future development plans andcurrent market values. Our undeveloped properties are predominantly held-by-production, which reduces the risk of impairment as a result of leaseexpirations. There were no impairments of unproved properties during 2017 and 2016 and we impaired $88.1 million of unproved properties during 2015.The impairment was recorded to reflect the estimated fair value of our undeveloped properties as a result of the decline in oil and natural gas prices. Theimpairment also included certain expiring acreage that was no longer part of our drilling plans. See "Note 6. Fair value measurements" for further discussion.We capitalize interest on the costs related to the acquisition of undeveloped acreage in accordance with FASB ASC 835-20, Capitalization of Interest.When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we ceasecapitalizing interest related to these properties. We capitalize the portion of general and administrative costs, including share-based compensation, that isattributable to our acquisition, exploration, exploitation and development activities.We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unprovedproperties, and all estimated future development costs less estimated salvage value are divided by86Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.the total estimated quantities of Proved Reserves. This rate is applied to our total production for the quarter, and the appropriate expense is recorded.Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gainor loss, unless the disposition would significantly alter the relationship between capitalized costs and Proved Reserves.Pursuant to Rule 4-10(c)(4) of Regulation S-X, at the end of each quarterly period, companies that use the full cost method of accounting for their oiland natural gas properties must compute a limitation on capitalized costs ("ceiling test"). The ceiling test involves comparing the net book value of the fullcost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling limitation is less than the full cost pool, we arerequired to record a ceiling test impairment of our oil and natural gas properties. The full cost ceiling limitation is computed as the sum of the present valueof estimated future net revenues from our Proved Reserves by applying the average price as prescribed by the SEC Release No. 33-8995, less estimated futureexpenditures (based on current costs) to develop and produce the Proved Reserves, discounted at 10%, plus the cost of properties not being amortized and thelower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects.The ceiling test for each period presented was based on the following average spot prices, in each case adjusted for quality factors and regionaldifferentials to derive estimated future net revenues. Prices presented in the table below are the trailing 12 month simple average spot prices at the first of themonth for natural gas at Henry Hub ("HH") and West Texas Intermediate ("WTI") crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatilityin oil and natural gas prices between each of the periods and have a significant impact on our ceiling test limitation. Average spot prices Oil (per Bbl) Natural gas (per Mmbtu)December 31, 2017 $51.34 $2.98December 31, 2016 42.75 2.48December 31, 2015 50.28 2.59For the year ended December 31, 2017, we did not recognize impairments to our proved oil and natural gas properties. For the year endedDecember 31, 2016 and 2015, we recognized impairments to our proved oil and natural gas properties of $160.8 million and $1.2 billion, respectively. Theimpairments were primarily due to the decline in oil and natural gas prices. As of December 31, 2017, we did not recognize any Proved Undeveloped Reserves due to our inability to meet the Reasonable Certainty criteria asprescribed under the SEC requirements as a result of the uncertainty regarding our availability of capital required to develop these reserves. We have asignificant amount of reserves that would meet the criteria to be classified as Proved Undeveloped Reserves if we were able to demonstrate the financialcapability to execute a development plan.Under full cost accounting rules, any ceiling test impairments of oil and natural gas properties may not be reversed in subsequent periods. Since we donot designate our derivative financial instruments as hedging instruments, we are not allowed to use the impacts of the derivative financial instruments in ourceiling test computations.The evaluation of impairment of our oil and natural gas properties includes estimates of Proved Reserves. There are numerous uncertainties inherent inestimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserveestimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing andproduction subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oiland natural gas that are ultimately recovered.Other property and equipment, net and other non-current assetsOther property and equipment, net and other non-current assets is primarily comprised of surface acreage and buildings and equipment associated withfield offices located in our South Texas region. The buildings and equipment are capitalized at cost and depreciated on a straight line basis over theirestimated useful lives ranging from 3 to 15 years.87Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.GoodwillIn accordance with FASB ASC 350-20, Intangibles-Goodwill and Other ("ASC 350-20"), goodwill is not amortized, but is tested for impairment on anannual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of thebusiness operations with which goodwill is associated, are performed as of December 31 of each year. Losses, if any, resulting from impairment tests will bereflected in operating income or loss in the Consolidated Statements of Operations.We consider our enterprise value, calculated as the combined market capitalization of our equity plus the fair value of our debt, in determining the fairvalue of our reporting unit. As part of the determination of the fair value of our reporting unit, we corroborate our enterprise value to the results of thevaluation model in which we apply a two-part, equally weighted approach in determining the fair value of our business. We perform an income approach,which uses a discounted cash flow model to value our business, and a market approach, in which our value is determined using trading metrics andtransaction multiples of peer companies.As a result of testing, the fair value of our business significantly exceeded the carrying value of net assets at December 31, 2017 and we did not recordan impairment charge for the periods ending December 31, 2017, 2016 or 2015.Asset retirement obligationsWe apply FASB ASC 410-20, Asset Retirement and Environmental Obligations ("ASC 410-20") to account for estimated future plugging andabandonment costs. ASC 410-20 requires legal obligations associated with the retirement of long-lived assets to be recognized at their estimated fair value atthe time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset and allocated toexpense over the useful life of the asset. Our asset retirement obligations primarily represent the present value of the estimated amount we will incur to plug,abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state laws.The following is a reconciliation of our asset retirement obligations for the periods indicated: December 31,(in thousands) 2017 2016 2015Asset retirement obligations at beginning of period $11,289 $41,648 $36,755Activity during the period: Liabilities incurred during the period 12 — 881Revisions in estimated assumptions — 175 3,215Liabilities settled during the period (175) (140) (293)Adjustment to liability due to acquisitions 17 1 180Adjustment to liability due to divestitures (1) — (32,605) (1,367)Accretion of discount 874 2,210 2,277Asset retirement obligations at end of period 12,017 11,289 41,648Less current portion 600 344 845Long-term portion $11,417 $10,945 $40,803(1)For the year ended December 31, 2016, the adjustment to liability due to divestitures consisted primarily of $22.6 million and $9.7 million from the sales of ourconventional assets located in Pennsylvania and West Virginia, respectively.Our asset retirement obligations are determined using discounted cash flow methodologies based on inputs and assumptions developed bymanagement. We do not have any assets that are legally restricted for purposes of settling asset retirement obligations.Revenue recognition and gas imbalancesWe use the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes ofoil and natural gas sold to purchasers. Gas imbalances at December 31, 2017, 2016 and 2015 were not significant.88Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Gathering and transportationWe generally sell oil and natural gas under two types of agreements which are common in our industry. Both types of agreements include atransportation charge. One is a net-back arrangement, under which we sell oil or natural gas at the wellhead and collect a price, net of the transportationincurred by the purchaser. In this case, we record sales at the price received from the purchaser, net of the transportation costs. Under the other arrangement,we sell oil or natural gas at a specific delivery point, pay transportation to a third party and receive proceeds from the purchaser with no transportationdeduction. In this case, we record the transportation cost as gathering and transportation expense. As such, our computed realized prices, before the impact ofderivative financial instruments, include revenues which are reported under two separate bases. Gathering and transportation expenses totaled $111.4million, $106.5 million and $99.3 million for the years ended December 31, 2017, 2016 and 2015, respectively.Capitalization of internal costsAs part of our proved developed oil and natural gas properties, we capitalize a portion of salaries and related share-based compensation for employeeswho are directly involved in the acquisition, appraisal, exploration, exploitation and development of oil and natural gas properties. During the years endedDecember 31, 2017, 2016 and 2015, we capitalized $3.9 million, $4.0 million and $10.6 million, respectively. The capitalized amounts include $1.0 million,$0.8 million and $3.4 million of share-based compensation for the years ended December 31, 2017, 2016 and 2015, respectively.Overhead reimbursement feesWe have classified fees from overhead charges billed to working interest owners of $14.6 million, $13.7 million and $13.1 million for the years endedDecember 31, 2017, 2016 and 2015, respectively, as a reduction of general and administrative expenses in the accompanying Consolidated Statements ofOperations. We classified our share of these charges as oil and natural gas production costs in the amount of $6.0 million, $5.8 million and $5.7 million forthe years ended December 31, 2017, 2016 and 2015, respectively.In addition, we have agreements with Shell that allow us to bill each other certain personnel costs and related fees incurred on behalf of the jointventures in the East Texas, North Louisiana and Appalachia regions. For the years ended December 31, 2017, 2016 and 2015, general and administrativeexpenses were reduced by $6.4 million, $7.1 million and $15.9 million, respectively, for recoveries of fees for our personnel and services provided to ourjoint ventures and other partners. These recoveries are net of fees charged to us by Shell for their personnel and services.Environmental costsEnvironmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by pastoperations are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently availablefacts related to each site.Income taxesIncome taxes are accounted for in accordance with FASB ASC 740, Income Taxes ("ASC 740"), under which deferred income taxes are recognized forthe future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using theenacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in earnings in the period that includes theenactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not berealized.Earnings per shareWe account for earnings per share in accordance with FASB ASC 260-10, Earnings Per Share ("ASC 260-10"). ASC 260-10 requires companies topresent two calculations of earnings per share ("EPS"): basic and diluted. Basic EPS is based on the weighted average number of common shares outstandingduring the period and includes warrants representing the right to purchase our common shares at an exercise price of $0.01. Basic EPS excludes stock options,restricted share units, restricted share awards, warrants issued Energy Strategic Advisory Services LLC ("ESAS", the warrants are referred to as "ESASWarrants") and Financing Warrants (as defined in "Note 4. Derivative financial instruments"). Diluted EPS is computed in the same manner as basic EPS afterassuming the issuance of common shares for all potentially dilutive common share equivalents,89Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.which include stock options, restricted share units, restricted share awards, ESAS Warrants and Financing Warrants, whether exercisable or not.Equity-based compensationOur equity-based compensation includes share-based compensation to employees which we account for in accordance with FASB ASC 718,Compensation-Stock Compensation ("ASC 718") and equity-based compensation for ESAS Warrants which we accounted for in accordance with FASB ASC505-50, Equity-Based Payments to Non-Employees ("ASC 505-50"). See "Note 13. Related party transactions" for further discussion.ASC 718 requires all share-based payments to employees, including grants of employee stock options, restricted share units and restricted shareawards, to be recognized in our Consolidated Statements of Operations based on their estimated fair values. We recognize expense on a straight-line basisover the vesting period of the option, restricted share unit or restricted share award. We capitalize part of our share-based compensation that is attributable toour acquisition, exploration, exploitation and development activities.Our 2005 Amended and Restated Long-Term Incentive Plan ("2005 Incentive Plan") provides for the granting of options and other equity incentiveawards of our common shares in accordance with terms within the agreements. New shares will be issued for any options exercised or awards granted. Underthe 2005 Incentive Plan, we have only issued stock options, restricted share units and restricted share awards, although the plan allows for other share-basedawards. We have discontinued the grant of share-based compensation to officers and employees until the completion of a restructuring. As a result, there wereno grants of share-based compensation during 2017. See further discussion in "Note 11. Equity-based and other incentive-based compensation".The measurement of the ESAS Warrants was accounted for in accordance with ASC 505-50, which required the warrants to be re-measured each interimreporting period until the completion of the services under the agreement and an adjustment was recorded in our Consolidated Statements of Operationsincluded as equity-based compensation expense. The ESAS Warrants were forfeited and canceled on November 9, 2017 concurrently with the suspension ofthe services and investment agreement with ESAS. See "Note 11. Equity-based and other incentive-based compensation" for additional information of theESAS Warrants.Recent accounting pronouncementsIn February 2016, the FASB issued Accounting Standards Update ("ASU") No. 2016-02, Leases (Topic 842) ("ASU 2016-02"). The main differencebetween the current requirement under GAAP and ASU 2016-02 is the recognition of lease assets and lease liabilities by lessees for those leases classified asoperating leases. ASU 2016-02 requires that a lessee recognize in the statement of financial position a liability to make lease payments (the lease liability)and a right-of-use asset representing its right to use the underlying asset for the lease term (other than leases that meet the definition of a short-term lease). Theliability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. Forincome statement purposes, the FASB retained a dual model, requiring leases to be classified as either operating or finance. Operating leases will result instraight-line expense (similar to current operating leases) while finance leases will result in a front-loaded expense pattern (similar to current capital leases).Classification will be based on criteria that are largely similar to those applied in current lease accounting. For lessors, the guidance modifies theclassification criteria and the accounting for sales-type and direct financing leases. ASU 2016-02 is effective for annual and interim periods beginning afterDecember 15, 2018 and early adoption is permitted. ASU 2016-02 must be adopted using a modified retrospective transition, and provides for certainpractical expedients. These transactions will require application of the new guidance at the beginning of the earliest comparative period presented. We arecurrently assessing the potential impact of ASU 2016-02 and expect it may have an impact on our consolidated financial condition and results of operationsupon adoption.90Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and CashPayments ("ASU 2016-15"). ASU 2016-15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows. Theamendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing,contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement ofcorporate-owned life insurance policies and distributions received from equity method investees. ASU 2016-15 is effective for annual and interim periodsbeginning after December 15, 2017, and early adoption is permitted. We adopted ASU 2016-15 in the fourth quarter of 2017, and elected to apply thecumulative earnings approach to classify distributions received from equity method investees.In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory ("ASU 2016-16"). The amendments in this update require that an entity recognize the income tax consequences of an intra-entity transfer of an asset other than inventorywhen the transfer occurs. Consequently, the amendments in this update eliminate the exception for an intra-entity transfer of an asset other than inventory.ASU 2016-16 is effective for annual and interim periods beginning after December 15, 2017 and early adoption is permitted. We assessed ASU 2016-16 andconcluded it did not have an impact on our consolidated financial condition and results of operations.In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB EmergingIssues Task Force) ("ASU 2016-18"). The amendments in this update require that a statement of cash flows explain the change during the period in total cash,cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cashand restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amountsshown on the statement of cash flows. ASU 2016-18 is effective for annual and interim periods beginning after December 15, 2017 and early adoption ispermitted. We are currently assessing the potential impact of ASU 2016-18 on our consolidated financial condition and results of operations and will applyASU 2016-18 beginning with the first quarter of 2018.In January 2017, the FASB issued Accounting Standards Update ("ASU") No. 2017-01, Business Combinations (Topic 805): Clarifying the Definitionof a Business ("ASU 2017-07"). ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017. Under ASU 2017-01, an entitymust first determine whether substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similarassets. If this threshold is met, the set is not a business. If this threshold is not met, the entity then evaluates whether the set meets the requirement that abusiness include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create outputs. We are currentlyassessing the potential impact of ASU 2017-01 on our consolidated financial condition and results of operations and will apply ASU 2017-07 to future assetacquisitions occurring in annual and interim periods beginning after December 15, 2017.In January 2017, the FASB issued ASU No. 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment("ASU 2017-04"). ASU 2017-04 eliminates Step 2 of the goodwill impairment test. Instead, an entity should perform its annual or interim goodwillimpairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount bywhich the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated tothat reporting unit. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test isnecessary. ASU 2017-04 is effective for annual and interim periods beginning after December 15, 2019 and early adoption is permitted for interim or annualgoodwill impairment tests performed after January 1, 2017. We early adopted ASU 2017-04 during 2017, and will apply the guidance in ASU 2017-04, ifapplicable, to future goodwill impairment tests.In May 2017, the FASB issued ASU No. 2017-09, Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting ("ASU 2017-09"). ASU 2017-09 provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to applymodification accounting in Topic 718. ASU 2017-09 is effective for annual and interim periods beginning after December 15, 2017, and early adoption ispermitted. We adopted ASU 2017-09 in the current period; however, the adoption of ASU 2017-09 did not have an impact on our consolidated financialcondition and results of operations. We will apply the guidance in ASU 2017-09 in future periods, if applicable.In July 2017, the FASB issued ASU No. 2017-11, Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), Derivatives andHedging (Topic 815): I. Accounting for Certain Financial Instruments with Down Round Features, II. Replacement of the Indefinite Deferral forMandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a ScopeException ("ASU 2017-11"). ASU 2017-11 revises the guidance for instruments with down round features in Subtopic 815-40, Derivatives and Hedging -91Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Contracts in Entity’s Own Equity, which is considered in determining whether an equity-linked financial instrument qualifies for a scope exception fromderivative accounting. An entity still is required to determine whether instruments would be classified in equity under the guidance in Subtopic 815-40 indetermining whether they qualify for that scope exception. If they do qualify, freestanding instruments with down round features are no longer classified asliabilities. Our 2017 Warrants are required to be classified as liabilities under the current guidance due to their down round features. The amendments in Part Iare required to be applied retrospectively to outstanding financial instruments with down round features. ASU 2017-11 is effective for annual and interimperiods beginning after December 15, 2018, and early adoption is permitted, including adoption in an interim period. We are currently assessing the impactof ASU 2017-11; however, we believe that it may have a significant impact on our consolidated financial condition and results of operations if we determinethe 2017 Warrants qualify for equity classification. During the year ended December 31, 2017, we recorded a gain of $159.2 million on the revaluation of the2017 Warrants on the Consolidated Statements of Operations and a liability of $2.0 million on the Consolidated Balance Sheet as of December 31, 2017.Revenue from Contracts with Customers (Topic 606)In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) ("ASU 2014-09"). The FASB and theInternational Accounting Standards Board ("IASB") jointly issued this comprehensive new revenue recognition standard that will supersede nearly allexisting revenue recognition guidance under GAAP. The core principle of the guidance is that an entity should recognize revenue to depict the transfer ofpromised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods orservices. In doing so, companies will need to use more judgment and make more estimates than under currently applicable guidance, including identifyingperformance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transactionprice to each separate performance obligation. The FASB issued additional ASUs that primarily clarified the implementation guidance on principal versusagent considerations, performance obligations and licensing, collectability, presentation of sales taxes and other similar taxes collected from customers, andnon-cash consideration. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017 and permits the use of either theretrospective or cumulative effect transition method.We are substantially complete with our assessment of the impact of ASU 2014-09 and the related updates and clarifications. ASU 2014-09 and therelated updates will be implemented for the interim and annual periods beginning after December 15, 2017 and the new standard will be applied using themodified retrospective method of adoption. We do not believe this standard will have a material impact, if any, on our consolidated financial condition andresults of operations. However, the adoption of the standard will require that we provide expanded disclosures related to the nature, amount, timing anduncertainty of revenue and cash flows arising from contracts with customers. We plan to complete the implementation of processes to ensure new contractsare reviewed for the appropriate accounting treatment and generate the disclosures required under the new standard prior to the filing of our Form 10-Q for thethree months ended March 31, 2018.3.Acquisitions, divestitures and other significant events2017 Acquisitions and termination of South Texas divestitureTermination of South Texas divestitureOn April 7, 2017, we entered into a purchase and sale agreement with a subsidiary of Venado Oil and Gas, LLC ("Venado") to divest our oil and naturalgas properties and surface acreage in South Texas for a total purchase price of $300.0 million that was subject to closing conditions and adjustments based onan effective date of January 1, 2017.Pursuant to the terms of the agreement, the closing of the transaction was originally anticipated to occur on June 1, 2017 (the “Original ScheduledClosing Date”), unless certain conditions had not been satisfied or waived on or prior to the Original Scheduled Closing Date. The purchase agreementincluded conditions to the closing, including seller's representation and warranty regarding all material contracts being in full force and effect be true as ofthe Original Scheduled Closing Date. On May 31, 2017, Chesapeake Energy Marketing, L.L.C. (“CEML”) purportedly terminated a long-term natural gassales contract with an expiration of June 30, 2032, between CEML and Raider Marketing, LP (“Raider”), a wholly owned subsidiary of EXCO.On June 6, 2017, we filed a petition, application for temporary restraining order and temporary injunction against CEML and subsequently added theparent entity, Chesapeake Energy Corporation ("CEC"). In the lawsuit, we assert breach of contract, tortious interference with existing contract, tortiousinterference with prospective business relations, and declaratory relief that the contract is still in full force and effect. On June 7, 2017, CEML filed to removethe lawsuit to the United States92Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.District Court Northern District of Texas. On June 9, 2017, the District Court denied our motion for temporary restraining order. CEC filed a motion to dismisson the basis of personal jurisdiction, and the motion remains pending.Due to the purported contract termination, the closing conditions were not anticipated to be satisfied or waived by the Original Scheduled ClosingDate. Therefore, we entered into an amendment to extend the Original Scheduled Closing Date to August 15, 2017. The amendment, among other things,provided that the satisfaction of the closing conditions would be deemed satisfied by the reinstatement of the natural gas sales contract or by entry into a newgathering agreement. Because all closing conditions had not been satisfied or waived by August 15, 2017, EXCO and Venado mutually agreed to terminatethe purchase and sale agreement, effective as of August 15, 2017. Following the termination, the purchase and sale agreement was void and of no furthereffect.North Louisiana acquisitionsDuring the year ended December 31, 2017, we closed acquisitions of certain oil and natural gas properties and undeveloped acreage in the NorthLouisiana region for $24.2 million. The total purchase price was primarily allocated to $5.2 million of unproved oil and natural gas properties and $19.0million of proved oil and natural gas properties.2016 DivestituresSouth Texas transactionOn May 6, 2016, we closed a sale of certain non-core undeveloped acreage in South Texas and our interests in four producing wells for $11.5 million,after final purchase price adjustments. Proceeds from the sale were used to reduce indebtedness under the EXCO Resources Credit Agreement (as defined in"Note 5. Debt").Conventional asset divestituresOn July 1, 2016, we closed the sale of our interests in shallow conventional assets located in Pennsylvania and received an overriding royalty interestin each well. In addition, we retained all rights to other formations below the conventional depths in this region including the Marcellus and Utica shales. Forthe six months ended June 30, 2016, the divested assets produced approximately 6 Mmcfe per day and the revenues less direct operating expenses, excludinggeneral and administrative costs, generated a net loss of less than $0.1 million. The asset retirement obligations related to the divested wells were $22.6million on July 1, 2016.On October 3, 2016, we closed the sale of our interests in shallow conventional assets located primarily in West Virginia for approximately $4.5million, subject to customary post-closing purchase price adjustments. We retained all rights to other formations below the conventional depths in this regionincluding the Marcellus and Utica shales. For the nine months ended September 30, 2016, the divested assets produced approximately 4 Mmcfe per day andthe revenues less direct operating expenses, excluding general and administrative costs, generated net income of $0.7 million. The asset retirementobligations related to the divested wells were $9.7 million on October 3, 2016.The divestitures of our interests during 2016 did not significantly alter the relationship between our capitalized costs and Proved Reserves and wereaccounted for as an adjustment of capitalized costs with no gain or loss recognized in accordance with Rule 4-10(c)(6)(i) of Regulation S-X.2015 Acquisitions and termination of Participation AgreementIn July 2013, we entered into a participation agreement with a joint venture partner for the development of certain assets in the Eagle Ford shale("Participation Agreement"). The Participation Agreement required us to offer to purchase our joint venture partner's working interest in wells that have beenon production for at least one year. The offers were made on a quarterly basis for a group of wells based on prices defined in the Participation Agreement,subject to specific well criteria and return hurdles.We closed the first acquisition of our joint venture partner's interest in 3 gross (1.4 net) wells on March 11, 2015 for a total purchase price of $7.6million.During the fourth quarter of 2015, our Eagle Ford joint venture partner purported to accept our offer under the Participation Agreement to purchaseinterests in 21 gross (10.3 net) wells for $42.7 million, subject to purchase price adjustments subsequent to the effective date of June 30, 2015. We notifiedour joint venture partner that we did not intend to93Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.close this acquisition as our partner's purported acceptance had not been received in a timely manner under the terms of the Participation Agreement, and ourjoint venture partner filed a petition for injunctive relief and damages alleging that, among other things, we breached our obligation under the ParticipationAgreement. In addition, subsequent offers were also in dispute for various reasons.On July 25, 2016, we settled the litigation with our joint venture partner, and the litigation was thereafter dismissed after a final judgment order wasentered in response to the parties’ joint motion to dismiss the case with prejudice. Among other things, the settlement provided a full release for any claims,rights, demands, damages and causes of action that either party has asserted or could have asserted for any breach of the Participation Agreement. As part ofthe settlement, the parties amended and restated the Participation Agreement to (i) eliminate our requirement to offer to purchase our joint venture partner'sinterests in certain wells each quarter, (ii) eliminate our requirement to convey a portion of our working interest to our joint venture partner uponcommencing development of future locations, (iii) terminate the area of mutual interest, which required either party acquiring an interest in non-producingacreage included in certain areas to provide notice of the acquisition to the non-acquiring party and allowed the non-acquiring party to acquire aproportionate share in such acquired interest, (iv) provide that EXCO transfer to its joint venture partner a portion of its interests in certain producing wellsand certain undeveloped locations in South Texas (“Transferred Interests”), effective May 1, 2016 and (v) modify or eliminate certain other provisions. TheParticipation Agreement was terminated on December 1, 2016 upon final settlement of the agreement.We recorded a loss in "Other operating items" in the Consolidated Statements of Operations, and a corresponding credit to the "Proved developed andundeveloped oil and natural gas properties" in our Consolidated Balance Sheet during 2016. The fair value of the Transferred Interests was $23.2 million asof July 25, 2016 based on a discounted cash flow model of the estimated reserves using NYMEX forward strip prices. See "Note 6. Fair value measurements"for additional information. The net production from the Transferred Interests was approximately 350 Bbls of oil per day during June 2016.4.Derivative financial instrumentsOur derivative financial instruments are comprised of commodity derivative contracts and common share warrants.The table below presents the effect of derivative financial instruments on our Consolidated Balance Sheets:(in thousands) December 31, 2017 December 31, 2016Current assets Derivative financial instruments - commodity derivatives $1,150 $—Long-term assets Derivative financial instruments - commodity derivatives — 482Current liabilities Derivative financial instruments - commodity derivatives — (27,711)Long-term liabilities Derivative financial instruments - commodity derivatives — (464) Net commodity derivative financial instruments $1,150 $(27,693) Long-term liabilities Derivative financial instruments - common share warrants $(1,950) $—The table below presents the effect of derivative financial instruments on our Consolidated Statement of Operations: Year Ended December 31,(in thousands) 2017 2016 2015Gain (loss) on derivative financial instruments - commodity derivatives $24,732 $(34,137) $75,869Gain on derivative financial instruments - common share warrants 159,190 — —Commodity derivative financial instrumentsOur primary objective in entering into commodity derivative financial instruments is to manage our exposure to commodity price fluctuations, protectour returns on investments and achieve a more predictable cash flow from operations. These transactions limit exposure to declines in commodity prices, butalso limit the benefits we would realize if commodity prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of ourcommodity derivative financial instruments consists of non-cash income or expense due to changes in the fair value. Cash losses or gains only arise frompayments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration. We do not designate our commodityderivative financial instruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respectiveinstruments’ fair value in earnings.94Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from, or cash disbursements to, ourderivative contract counterparties. Changes in the fair value of our derivative financial instrument contracts, which include both cash settlements and non-cash changes in fair value, are included in earnings with a corresponding increase or decrease in the Consolidated Balance Sheets fair value amounts.Our oil and natural gas derivative instruments have historically been comprised of the following instruments:Swaps: These contracts allow us to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity.Collars: A collar is a combination of options including a sold call and a purchased put. These contracts allow us to participate in the upside ofcommodity prices to the ceiling of the call option and provide us with downside protection through the put option. If the market price is below the strikeprice of the purchased put at the time of settlement then the counterparty pays us the excess. If the market price is above the strike price of the sold call at thetime of settlement, we pay the counterparty the excess. These transactions were conducted contemporaneously with a single counterparty and resulted in anet cashless transaction.We have historically entered into commodity derivative financial instruments with the financial institutions that are lenders under the EXCOResources Credit Agreement. To mitigate our risk of loss due to default, we have entered into master netting agreements with counterparties to ourcommodity derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty.Our credit rating and financial condition have restricted our ability to enter into certain types of commodity derivative financial instruments and limited thematurity of the contracts with counterparties. The DIP Credit Agreement (as defined in "Note 5. Debt") permits us to enter into commodity derivativecontracts up to 90% of the reasonably anticipated projected production from our proved developed producing reserves for any month during the forthcomingfive year period. We are only permitted to enter into additional commodity derivative contracts with lenders under the DIP Credit Agreement.The following table presents the volumes and fair value of our commodity derivative financial instruments as of December 31, 2017:(dollars in thousands, except prices) Volume (Bbtu) Weighted average strikeprice per Mmbtu Fair value atDecember 31, 2017Natural gas: Swaps: 2018 3,650 $3.15 $1,150In January 2018, the counterparty to our remaining swap contracts early terminated the outstanding contracts effective January 31, 2018. We receivedproceeds of $0.5 million for the settlement these contracts in February 2018. As a result, our exposure to commodity price fluctuations will increase in 2018due to lower oil and natural gas volumes covered by derivative contracts compared to historical levels.At December 31, 2016, we had outstanding swap and collar contracts covering 41,950 and 10,950 Bbtu of natural gas, respectively, and outstandingswap contracts covering 183 Mbbls of oil.At December 31, 2017, the average forward NYMEX HH natural gas price per Mmbtu for the calendar year 2018 was $2.84.Our commodity derivative financial instruments covered approximately 58% and 57% of production volumes for the years ended December 31, 2017and 2016.Common share warrantsIn connection with the issuance of the 1.5 Lien Notes, on March 15, 2017, we issued warrants to the investors of 1.5 Lien Notes representing the rightto purchase an aggregate of up to 21,505,383 common shares (assuming a cash exercise) at an exercise price of $13.95 per share ("Financing Warrants"), andwarrants representing the right to purchase an aggregate of up to 431,433 common shares (assuming a cash exercise) at an exercise price of $0.01 per share(“Commitment Fee Warrants”). In addition, certain exchanging holders of the Second Lien Term Loans received warrants representing the right to purchasean95Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.aggregate of up to 1,325,546 common shares (assuming a cash exercise) at an exercise price of $0.01 per share ("Amendment Fee Warrants", and with theCommitment Fee Warrants and Financing Warrants, collectively referred to as the "2017 Warrants"). See "Note 5. Debt" for further discussion of the SecondLien Term Loans.Subject to certain exceptions and limitations, the 2017 Warrants may not be exercised if, as a result of such exercise, the holder of such 2017 Warrantsor its affiliates would beneficially own, directly or indirectly, more than 50% of our outstanding common shares. Each of the 2017 Warrants has an exerciseterm of 5 years from May 31, 2017 and, subject to certain exceptions, may be exercised by cash or cashless exercise. The Financing Warrants are subject to ananti-dilution adjustment in the event we issue common shares for consideration less than the market value of our common shares or exercise price of theFinancing Warrants, subject to certain adjustments and exceptions. The Commitment Fee Warrants and the Amendment Fee Warrants are subject to an anti-dilution adjustment in the event we issue common shares at a price per share less than $10.50 per share, subject to certain exceptions and adjustments. The2017 Warrants are accounted for as derivatives in accordance with ASC 815, and required to be classified as liabilities due to the types of anti-dilutionadjustments.We record the 2017 Warrants as non-current liabilities at fair value, with the increase or decrease in fair value being recognized in earnings. The 2017Warrants will be measured at fair value on a recurring basis until the date of exercise, cancellation or expiration. As a result of the change in the fair value ofthe 2017 Warrants, we recorded a gain of $159.2 million on the revaluation of the warrants during year ended December 31, 2017 in "Gain on derivativefinancial instruments - common share warrants" on the Consolidated Statements of Operations. The gain was primarily due to a decrease in EXCO's shareprice. In January 2018, the 2017 Warrants held by affiliates of Fairfax were canceled; see further discussion in "Note 13. Related party transactions".5.DebtThe carrying value of our total debt is summarized as follows:(in thousands) December 31, 2017 December 31, 2016EXCO Resources Credit Agreement $126,401 $228,5921.5 Lien Notes, net of unamortized discount 176,560 —1.75 Lien Term Loans, net of unamortized discount 845,763 —Exchange Term Loan 23,543 590,477Fairfax Term Loan — 300,0002018 Notes, net of unamortized discount 131,345 131,0562022 Notes 70,169 70,169Deferred financing costs, net (11,281) (11,756)Total debt, net 1,362,500 1,308,538Less amounts due within one year 1,362,500 50,000Total debt due after one year $— $1,258,538 December 31, 2017(in thousands) Carrying value Deferred reduction incarrying value Unamortizeddiscount/deferredfinancing costs Principal balanceEXCO Resources Credit Agreement $126,401 $— $— $126,4011.5 Lien Notes 176,560 — 140,398 316,9581.75 Lien Term Loans 845,763 (154,171) 17,334 708,926Exchange Term Loan 23,543 (6,297) — 17,2462018 Notes 131,345 — 231 131,5762022 Notes 70,169 — — 70,169Deferred financing costs, net (11,281) — 11,281 —Total debt $1,362,500 $(160,468) $169,244 $1,371,27696Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Terms and conditions of each of these debt obligations are discussed below.DIP Credit AgreementOn January 22, 2018, we closed a Debtor-in-Possession Credit Agreement (“DIP Credit Agreement”), which includes a senior secured debtor-in-possession revolving credit facility in an aggregate principal amount of $125.0 million (“Revolver A Facility”) and a senior secured debtor-in-possessionrevolving credit facility in an aggregate principal amount of $125.0 million (“Revolver B Facility”, and together with the Revolver A Facility, the “DIPFacilities”). The proceeds from the DIP Credit Agreement were used to refinance all obligations outstanding under our credit agreement ("EXCO ResourcesCredit Agreement") and provide additional liquidity to fund our operations during the Chapter 11 Cases. See further discussion of the DIP Credit Agreementin "Note 17. Subsequent events".EXCO Resources Credit AgreementAs of December 31, 2017, we borrowed substantially all of our remaining unused commitments and had $126.4 million of outstanding indebtednessand $23.0 million of outstanding letters of credit under the EXCO Resources Credit Agreement as of December 31, 2017. The borrowing base under theEXCO Resources Credit agreement was $150.0 million as of December 31, 2017. As a result, the availability remaining under the EXCO Resources CreditAgreement, including letters of credit, was $0.6 million as of December 31, 2017. Borrowings under the EXCO Resources Credit Agreement werecollateralized by first lien mortgages providing a security interest of not less than 80% of the engineered value, as defined in the agreement, in our oil andnatural gas properties covered by the borrowing base. As discussed above, the proceeds from the DIP Facilities were used to refinance all obligations underthe EXCO Resources Credit Agreement and the EXCO Resources Credit Agreement was terminated.The maturity date of the EXCO Resources Credit Agreement was July 31, 2018. The interest rate grid for the revolving commitment under the EXCOResources Credit Agreement ranged from London Interbank Offered Rate ("LIBOR") plus 250 bps to 350 bps (or alternate base rate ("ABR") plus 150 bps to250 bps), depending on our borrowing base usage. On December 31, 2017, our interest rate was approximately 4.9%.Concurrently with the issuance of the 1.5 Lien Notes and as a condition precedent thereto, on March 15, 2017, we amended the EXCO ResourcesCredit Agreement to, among other things, permit the issuance of the 1.5 Lien Notes and the exchanges of Second Lien Term Loans, reduce the borrowing basethereunder to $150.0 million and modify certain financial covenants. Our financial covenants (as defined in the EXCO Resources Credit Agreement),required that:•our cash (as defined in the EXCO Resources Credit Agreement) plus unused commitments under the EXCO Resources Credit Agreement cannot beless than (i) $50.0 million as of the end of a fiscal month and (ii) $70.0 million as of the end of a fiscal quarter;•our Aggregate Revolving Credit Exposure Ratio (as defined in the EXCO Resources Credit Agreement) cannot exceed 1.2 to 1.0 as of the end ofany fiscal quarter. Aggregate revolving credit exposure utilized in the Aggregate Revolving Credit Exposure Ratio includes borrowings andletters of credit under the EXCO Resources Credit Agreement; and•our Interest Coverage Ratio cannot be less than 2.0 to 1.0. The consolidated EBITDAX and consolidated interest expense utilized in this ratio arebased on the two fiscal quarters ended multiplied by 2.0 as of December 31, 2017, the most recent three fiscal quarters ended multiplied by 4/3 asof March 31, 2018, and the trailing twelve month period for fiscal quarters ending thereafter. The definition of consolidated interest expenseincludes cash interest payments that are accounted for as reductions in the carrying amount of indebtedness in accordance with FASB ASC 470-60, Troubled Debt Restructuring by Debtors. Consolidated interest expense is limited to payments in cash, and excludes PIK Payments (as definedbelow) on the 1.5 Lien Notes and 1.75 Lien Term Loans (as defined below).On December 19, 2017, we entered into a forbearance agreement with the lenders under the EXCO Resources Credit Agreement. Pursuant to thisagreement, the lenders under the EXCO Resources Credit Agreement agreed to forbear from exercising their rights and remedies until January 15, 2018, withrespect to anticipated events of default arising from the failure to pay interest on certain debt instruments and failure to comply with certain financialcovenants under the EXCO Resources Credit Agreement. An event of default as a result of a breach of any covenant under the EXCO Resources CreditAgreement could also cause an event of default under the indenture governing the 1.5 Lien Notes, credit agreement governing the 1.75 Lien Term Loans andthe indentures governing the 2018 Notes and 2022 Notes. FASB ASC 470, Debt, requires debt to be presented as a current liability if a debtor modifies acovenant in anticipation of a potential default and it is probable the debtor will not be able meet the covenant in future periods. Therefore, we have classifiedthe amounts outstanding under the EXCO Resources Credit Agreement, as well as any outstanding debt with cross-default provisions, as a current liability.97Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.1.5 Lien NotesOn March 15, 2017, we issued an aggregate of $300.0 million of 1.5 Lien Notes due March 20, 2022 to affiliates of Fairfax Financial Holdings Limited("Fairfax"), Bluescape Resources Company LLC ("Bluescape"), Oaktree Capital Management, LP ("Oaktree"), and an unaffiliated investor. The 1.5 Lien Notesbear interest at a cash interest rate of 8% per annum, or, if we elect to make interest payments on the 1.5 Lien Notes with our common shares or, in certaincircumstances, by issuing additional 1.5 Lien Notes, at an interest rate of 11% per annum. Interest is payable bi-annually on March 20 and September 20 ofeach year, commencing on September 20, 2017. On September 20, 2017 we paid the interest due on the 1.5 Lien Notes in-kind with approximately $17.0million of aggregate principal amount of 1.5 Lien Notes, resulting in $317.0 million of total aggregate principal amount of 1.5 Lien Notes outstanding. OnDecember 19, 2017, we entered into a forbearance agreement with certain lenders under the 1.5 Lien Notes. Pursuant to this agreement, the lenders under the1.5 Lien Notes agreed to forbear from exercising their rights and remedies until January 15, 2018, with respect to anticipated events of default arising fromthe failure to pay interest on certain debt instruments and failure to comply with certain financial covenants under the EXCO Resources Credit Agreement.As described in “Note 4. Derivative financial instruments,” in connection with the issuance of the 1.5 Lien Notes, we also issued the Commitment FeeWarrants and the Financing Warrants. The combined fair value of the Commitment Fee Warrants and the Financing Warrants of $148.6 million as of March15, 2017 and $4.5 million of cash paid to certain investors who elected to receive cash in lieu of Commitment Fee Warrants was recorded as a discount to the1.5 Lien Notes. The discount and $4.3 million of transaction costs incurred related to the transaction are being amortized to interest expense over the life ofthe 1.5 Lien Notes. We used the majority of the proceeds from the issuance of the 1.5 Lien Notes to repay the entire amount outstanding under the EXCOResources Credit Agreement in March 2017.The 1.5 Lien Notes are jointly and severally guaranteed by all of the our subsidiaries that guarantee our indebtedness under the EXCO ResourcesCredit Agreement, 1.75 Lien Term Loans and the Second Lien Term Loans, and are secured by first priority liens on substantially all of our assets and suchguarantors. The 1.5 Lien Notes rank pari passu in right of payment with one another and all of our other existing and future senior indebtedness, includingdebt under the EXCO Resources Credit Agreement, the 1.75 Lien Term Loans, the Second Lien Term Loans and the 2018 Notes and 2022 Notes. However, asa result of the debt under the EXCO Resources Credit Agreement having a priority claim to the collateral securing the 1.5 Lien Notes, the 1.5 Lien Notes are(i) effectively junior to debt under the EXCO Resources Credit Agreement and any other priority lien obligations, (ii) pari passu with one another, (iii)effectively senior to the 1.75 Lien Term Loans, the Second Lien Term Loans and any third lien obligations and (iv) effectively senior to all of our existingand future unsecured senior indebtedness, including the 2018 Notes and 2022 Notes, in each case to the extent of the collateral.1.75 Lien Term Loans and Second Lien Term Loan ExchangeDuring 2015, we closed a 12.5% senior secured second lien term loan with certain affiliates of Fairfax in the aggregate principal amount of $300.0million ("Fairfax Term Loan") and a 12.5% senior secured second lien term loan with certain unsecured noteholders in the aggregate principal amount of$400.0 million (“Exchange Term Loan" and together with the Fairfax Term Loan, "Second Lien Term Loans"). The proceeds from the Exchange Term Loanwere used to repurchase a portion of the outstanding 2018 Notes and 2022 Notes in exchange for the holders of such notes agreeing to act as lenders inconnection with the Exchange Term Loan. The exchange was accounted for as a troubled debt restructuring pursuant to FASB ASC 470-60, Troubled DebtRestructuring by Debtors. The future undiscounted cash flows from the Exchange Term Loan through its maturity were less than the carrying amounts of theretired 2018 Notes and 2022 Notes. As a result, the carrying amount of the Exchange Term Loan was adjusted to equal the total undiscounted future cashpayments, including interest and principal. All cash payments under the terms of the Exchange Term Loan, whether designated as interest or as principalamount, reduce the carrying amount and no interest expense is recognized.In connection with the offering of the 1.5 Lien Notes, on March 15, 2017, we completed the Second Lien Term Loan Exchange wherebyapproximately $682.8 million in aggregate principal amount of the outstanding Second Lien Term Loans, consisting of all of the outstanding indebtednessunder the Fairfax Term Loan and approximately $382.8 million in aggregate principal amount of the Exchange Term Loan, were exchanged forapproximately $682.8 million in aggregate principal amount of 1.75 Lien Term Loans. As a result of the Second Lien Term Loan Exchange, the Fairfax TermLoan was deemed satisfied and paid in full and was terminated. In addition, by participating in the Second Lien Term Loan Exchange, each exchanginglender was deemed to consent to an amendment to the Second Lien Term Loans that eliminated substantially all of the restrictive covenants and events ofdefault in the agreements governing the Second Lien Term Loans. Following the Second Lien Term Loan Exchange, the Company has approximately $17.2million in aggregate principal amount of Second Lien Term Loans outstanding, consisting entirely of the remaining portion of the Exchange Term Loan.98Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.The Second Lien Term Loan Exchange was accounted for as a modification of debt, and no gain or loss was recognized on the exchange. As describedin “Note 4. Derivative financial instruments,” in connection with the issuance of the 1.75 Lien Term Loans, we also issued the Amendment Fee Warrants. Thecombined fair value of the Amendment Fee Warrants issued to the lenders of the 1.75 Lien Term Loans on March 15, 2017 of $12.6 million and $8.6 millionof cash paid to the lenders who elected to receive cash in lieu of warrants was recorded as a discount to the 1.75 Lien Term Loans, and is being amortized tointerest expense over the life of the loans. The transaction costs related to the Second Lien Term Loan Exchange of $6.4 million were recorded in "Gain (loss)on restructuring and extinguishment of debt" in our Consolidated Statements of Operations for the year ended December 31, 2017.The 1.75 Lien Term Loans are due on October 26, 2020, bear interest at a cash rate of 12.5% per annum, or, if we elect to pay interest on the 1.75 LienTerm Loans with our common shares or, in certain circumstances, by issuing additional 1.75 Lien Term Loans, at an interest rate of 15.0% per annum. OnSeptember 20, 2017 we paid the interest due on the 1.75 Lien Term Loans in-kind with approximately $26.2 million of aggregate principal amount of 1.75Lien Term Loans, resulting in $708.9 million of total aggregate principal amount of 1.75 Lien Term Loans outstanding. On December 19, 2017, we enteredinto a forbearance agreement with certain lenders under the 1.75 Lien Term Loans. Pursuant to this agreement, the lenders under the 1.75 Lien Term Loansagreed to forbear from exercising their rights and remedies until January 15, 2018, with respect to anticipated events of default arising from the failure to payinterest on certain debt instruments and failure to comply with certain financial covenants under the EXCO Resources Credit Agreement. The December 20,2017 interest payment on the 1.75 Lien Term Loans was required to be paid in-kind pursuant to the terms of the indenture governing the 1.5 Lien Notes. Wehave not paid the interest on the 1.75 Lien Term Loans of $27.0 million, based on the rate of 15% for PIK Payments that was due on December 20, 2017.Also, we have not paid the interest on the Second Lien Term Loans of $0.5 million that was due on December 26, 2017. As a result of the failure to payinterest on the Second Lien Term Loans, we are currently in default of the agreement governing the Second Lien Term Loans and the outstanding balancewas classified as a current liability as of December 31, 2017.The 1.75 Lien Term Loans are jointly and severally guaranteed by all of our subsidiaries that guarantee the indebtedness under the EXCO ResourcesCredit Agreement and the Second Lien Term Loans, and are secured by first priority liens on substantially all of our assets and such guarantors. The 1.75 LienTerm Loans rank pari passu in right of payment with one another and all of our other existing and future senior indebtedness, including debt under the EXCOResources Credit Agreement, the 1.5 Lien Notes, the Second Lien Term Loans and the 2018 Notes and 2022 Notes. However, as a result of the debt under theEXCO Resources Credit Agreement and the 1.5 Lien Notes having a priority claim to the collateral securing the 1.75 Lien Term Loans, the 1.75 Lien TermLoans rank (i) effectively junior to debt under the EXCO Resources Credit Agreement, the 1.5 Lien Notes and any other priority lien obligations, (ii) paripassu with one another, (iii) effectively senior to the Second Lien Term Loans and any third lien obligations and (iv) effectively senior to all of our existingand future unsecured senior indebtedness, including the 2018 Notes and 2022 Notes, in each case to the extent of the collateral.PIK Payments under the 1.5 Lien Notes and the 1.75 Lien Term LoansThe principal purpose of issuing the 1.5 Lien Notes and Second Lien Term Loan Exchange was to alleviate our substantial cash interest paymentburden and improve our Liquidity. The indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans allow us tomake payments in additional indebtedness or common shares ("PIK Payments"), subject to certain restrictions and limitations.On June 20, 2017, we issued a total of 2,745,754 common shares ("PIK Shares") in lieu of an approximate $23.0 million cash interest payment underthe 1.75 Lien Term Loans. The number of PIK Shares issued was calculated based on the interest rate for PIK Payments of 15.0%, which resulted in a value of$27.6 million for the interest payment. The price of the Company's common shares for determining PIK Shares was based on the trailing 20-day volumeweighted average price calculated as of the end of the three trading days prior to February 28, 2017. On September 20, 2017, we paid approximately $17.0million and $26.2 million of PIK Payments under the 1.5 Lien Notes and 1.75 Lien Term Loans, respectively, through the issuance of additional 1.5 LienNotes and 1.75 Lien Term Loans.Our initial expectation was to make PIK Payments in common shares on the 1.5 Lien Notes and the 1.75 Lien Term Loans throughout the remainder of2017 and 2018. However, there were significant limitations on our ability to make PIK Payments during 2017. Under our Registration Rights Agreement withthe holders of the 1.5 Lien Notes and lenders of the 1.75 Lien Term Loans ("Registration Rights Agreement"), our ability to make PIK Payments in commonshares is subject to a resale registration statement related to the common shares issued as PIK Payments and all of the shares underlying the warrants issued inconnection with the 1.5 Lien Notes and 1.75 Lien Term Loans being declared effective by the SEC by October 11, 2017 ("Resale Registration Statement").We did not anticipate the Resale Registration Statement would be declared effective as of October 11, 2017, and, as such, we provided a notice of a delay ofeffectiveness for the Resale Registration Statement to the99Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.holders of the 1.5 Lien Notes and lenders of the 1.75 Lien Term Loans, as permitted under the Registration Rights Agreement, extending the requirement forthe Resale Registration Statement to be declared effective to no later than December 8, 2017. The Resale Registration Statement was not declared effectiveduring 2017; therefore, we were restricted in making PIK Payments in common shares subsequent to December 8, 2017.Even if the Resale Registration Statement was declared effective, the terms of the indenture governing the 1.5 Lien Notes and the credit agreementgoverning the 1.75 Lien Term Loans prohibit the issuance of common shares as PIK Payments if it would result in a beneficial owner, directly or indirectly,owning more than 50% of our outstanding common shares. Our common share price experienced a significant decline during 2017, which would haveresulted in the issuance of a greater number of common shares to make PIK Payments on the 1.5 Lien Notes and 1.75 Lien Term Loans. This could haveprevented us from being able to pay interest in common shares due to the 50% ownership limitation.The amount of PIK Payments made in additional 1.5 Lien Notes or 1.75 Lien Term Loans is subject to incurrence covenants within our debtagreements that limit our aggregate secured indebtedness to $1.2 billion. This amount is reduced dollar-for-dollar to the extent that we incur any additionalsecured indebtedness, including PIK Payments in additional indebtedness. After the PIK Payments in additional indebtedness on September 20, 2017, ourability to make future PIK Payments in additional indebtedness was limited to $6.9 million. This would not have been sufficient to make our next quarterlyinterest payment of approximately $26.9 million, based on the PIK interest rate of 15.0% on the 1.75 Lien Term Loans, that was scheduled to occur onDecember 20, 2017, and was required to be paid in-kind pursuant to the terms of the indenture governing the 1.5 Lien Notes. Furthermore, the agreementgoverning the 1.75 Lien Term Loans restricts our ability to pay interest in cash, unless we have liquidity, on a pro forma basis, of at least $175.0 million.After December 31, 2018, the amount of PIK Payments we are permitted to make is dependent upon our Liquidity, which, for the purposes of 1.5 LienNotes and 1.75 Lien Term Loans, is defined as (i) the sum of (a) our unrestricted cash and cash equivalents and (b) any amounts available to be borrowedunder the EXCO Resources Credit Agreement (to the extent then available) less (ii) the face amount of any letters of credit outstanding under the EXCOResources Credit Agreement.Covenants, events of default and other material provisions under the 1.5 Lien Notes and the 1.75 Lien Term LoansThe 1.5 Lien Notes and 1.75 Lien Term Loans are guaranteed by substantially all of EXCO’s subsidiaries, with the exception of certain non-guarantorsubsidiaries and our jointly-held equity investments with Shell. The 1.5 Lien Notes and 1.75 Lien Term Loans are secured by second priority liens and thirdpriority liens, respectively, on substantially all of EXCO’s assets and the assets of such guarantors. Subject to certain exceptions, the covenants under theindenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans limit our ability and the ability of our restrictedsubsidiaries to, among other things:•pay dividends or make other distributions or redeem or repurchase our common shares;•prepay, redeem or repurchase certain junior lien or unsecured debt;•enter into agreements restricting the subsidiary guarantors’ ability to pay dividends to us or another subsidiary guarantor, make loans or advancesto us or transfer assets to us;•engage in asset sales or substantially alter the business that we conduct;•enter into transactions with affiliates;•consolidate, merge or dispose of assets;•incur liens; and•enter into sale/leaseback transactions.In addition, the indenture governing the 1.5 Lien Notes includes restrictions on our ability to incur additional indebtedness, among other things andsubject to certain restrictions. The indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans require that net cashproceeds of certain asset sales be used within one year to acquire or develop oil and natural gas properties or we must use the proceeds to permanently repay,redeem or repurchase a portion of the EXCO Resources Credit Agreement, 1.5 Lien Notes or 1.75 Lien Term Loans. If there is an event of default, we will berequired to pay each of the 1.5 Lien Notes and the 1.75 Lien Term Loans in an amount equal to the outstanding principal amount plus an applicable make-whole premium.In connection with the offering of the 1.5 Lien Notes and the Second Lien Term Loan Exchange, we entered into an amended and restated intercreditoragreement, under which the lenders of the remaining outstanding portion of the Exchange Term Loan agreed to subordinate their security interest in thecollateral to the interests of the holders of the 1.5 Lien Notes, the 1.75 Lien Term Loans and the lenders under EXCO Resources Credit Agreement. Inaddition, the lenders of the 1.75 Lien Term Loans agreed to subordinate their security interest in the collateral to the interests of the holders of the 1.5 LienNotes and the100Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.lenders under the EXCO Resources Credit Agreement, and the holders of the 1.5 Lien Notes agreed to subordinate their security interest in the collateral tothe lenders under the EXCO Resources Credit Agreement.2018 NotesThe 2018 Notes are guaranteed on a senior unsecured basis by substantially all of EXCO’s subsidiaries. Our equity investments, other than OPCO,have been designated as unrestricted subsidiaries under the indenture governing the 2018 Notes.During 2015 and 2016, we completed exchanges and a series of open market repurchases of the 2018 Notes significantly reducing the aggregateprincipal amount outstanding. As of December 31, 2017, $131.6 million in principal was outstanding on the 2018 Notes. Interest accrues at 7.5% per annumand is payable semi-annually in arrears on March 15 and September 15 of each year. The maturity date of the 2018 Notes is September 15, 2018.The indenture governing the 2018 Notes contains covenants, which may limit our ability and the ability of our restricted subsidiaries to:•incur or guarantee additional debt and issue certain types of preferred shares;•pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;•make certain investments;•create liens on our assets;•enter into sale/leaseback transactions;•create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;•engage in transactions with our affiliates;•transfer or issue shares of stock of subsidiaries;•transfer or sell assets; and•consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries.2022 NotesThe 2022 Notes were issued at 100.0% of the principal amount and bear interest at a rate of 8.5% per annum, payable in arrears on April 15 andOctober 15 of each year. During 2015 and 2016, we completed exchanges and a series of open market repurchases of the 2022 Notes significantly reducingthe aggregate principal amount outstanding. As of December 31, 2017, $70.2 million in principal was outstanding on the 2022 Notes.The 2022 Notes rank equally in right of payment to any existing and future senior unsecured indebtedness of the Company (including the 2018 Notes)and are guaranteed on a senior unsecured basis by EXCO’s consolidated subsidiaries that are guarantors of the indebtedness under the EXCO ResourcesCredit Agreement. The 2022 Notes were issued under the same base indenture governing the 2018 Notes and the supplemental indenture governing the 2022Notes contains similar covenants to those in the supplemental indenture governing the 2018 Notes.6.Fair value measurementsWe value our derivatives and other financial instruments according to FASB ASC 820, Fair Value Measurements and Disclosures ("ASC 820"), whichdefines fair value as the exchange price that would be received for an asset or paid to transfer a liability ("exit price") in the principal or most advantageousmarket for the asset or liability in an orderly transaction between market participants on the measurement date.We categorize the inputs used in measuring fair value into a three-tier fair value hierarchy. These tiers include:Level 1 – Observable inputs, such as quoted market prices in active markets, for substantially identical assets and liabilities.Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices in markets that arenot active or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractualterm, the input must be observable for substantially the full term of the asset or liability.Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring development of fair value assumptions bymanagement.101Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.During the years ended December 31, 2017 and 2016 there were no changes in the fair value level classifications, except that the Exchange Term Loanwas reclassified to Level 3.Fair value of derivative financial instrumentsThe following table presents a summary of the estimated fair value of our derivative financial instruments as of December 31, 2017 and 2016. December 31, 2017(in thousands) Level 1 Level 2 Level 3 TotalDerivative financial instruments - commodity derivatives $— $1,150 $— $1,150Derivative financial instruments - common share warrants — (1,950) — (1,950) December 31, 2016(in thousands) Level 1 Level 2 Level 3 TotalDerivative financial instruments - commodity derivatives $— $(27,693) $— $(27,693)Derivative financial instruments - commodity derivativesWe evaluate derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them on agross basis on our Consolidated Balance Sheets. Net derivative asset values are determined primarily by quoted futures prices and utilization of thecounterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined by utilization of our credit-adjusted risk-free rate curve. Thecredit-adjusted risk-free rates of our counterparties are based on an independent market-quoted credit default swap rate curve for the counterparties’ debt plusthe LIBOR curve as of the end of the reporting period. Our credit-adjusted risk-free rate is based on the blended rate of independent market-quoted creditdefault swap rate curves for companies that have the same credit rating as us plus the LIBOR curve as of the end of the reporting period.The valuation of our commodity price derivatives, represented by oil and natural gas swaps and collar contracts, is discussed below.Oil derivatives. Our oil derivatives consisted of swap contracts for notional barrels of oil at fixed NYMEX oil index prices. The asset and liabilityvalues attributable to our oil derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent activeNYMEX futures price quotes for oil index prices, and (iii) the applicable credit-adjusted risk-free rate curve, as described above.Natural gas derivatives. Our natural gas derivatives consisted of swap and collar contracts for notional Mmbtus of natural gas at posted price indexes,including NYMEX HH swap and option contracts. The asset and liability values attributable to our natural gas derivatives as of the end of the reportingperiod are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for natural gas, (iii) the applicable credit-adjusted risk-free rate curve, as described above, and (iv) the implied rates of volatility inherent in the option contracts. The implied rates of volatility weredetermined based on the average of historical HH natural gas prices.The fair value of our commodity derivative financial instruments may be different from the settlement value based on company-specific inputs, such ascredit ratings, futures markets and forward curves, and readily available buyers or sellers.Derivative financial instruments - common share warrantsThe liability attributable to our common share warrants as of the issuance date and the end of each reporting period was measured using the Black-Scholes model based on inputs including our share price, volatility, expected remaining life and the risk-free rate of return. The implied rates of volatilitywere determined based on historical prices of our common shares over a period consistent with the expected remaining life. Common share warrants aremeasured at fair value on a recurring basis until the date of exercise or the date of expiration.See further details on the fair value of our derivative financial instruments in “Note 4. Derivative financial instruments”.102Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Fair value of other financial instrumentsOur financial instruments include cash and cash equivalents, accounts receivable and payable and accrued liabilities. The carrying amount of theseinstruments approximates fair value because of their short-term nature.The carrying values of our borrowings under the revolving commitment of the EXCO Resources Credit Agreement approximates fair value, as it issubject to short-term floating interest rates that approximate the rates available to us for those periods.The estimated fair values of our senior notes and term loans are presented below. The estimated fair values of the 2018 Notes and 2022 Notes havebeen calculated based on quoted prices in active markets. The estimated fair value of the 1.5 Lien Notes, 1.75 Lien Term Loans and the Exchange Term Loanhave been calculated based on quoted prices obtained from third-party pricing sources that lack significant observable inputs and are classified as Level 3.The 2017 Warrants are considered freestanding financial instruments and are not considered in the determination of the fair value of the 1.5 Lien Notes and1.75 Lien Term Loans. The estimated fair value of the Exchange Term Loan was calculated based on quoted prices obtained from third-party sources andclassified as Level 2 during 2016. During the year ended December 31, 2017, we reclassified the fair value of the Exchange Term Loan into Level 3 due tothe lack of market activity and significant observable inputs. See "Note 5. Debt" for the carrying value and the principal balance of each debt instrumentincluded in the table below. December 31, 2017(in thousands) Level 1 Level 2 Level 3 Total1.5 Lien Notes $— $— $232,276 $232,2761.75 Lien Term Loans — — 372,186 372,186Exchange Term Loan — — 9,054 9,0542018 Notes 4,658 — — 4,6582022 Notes 2,586 — — 2,586 December 31, 2016(in thousands) Level 1 Level 2 Level 3 TotalExchange Term Loan $— $294,000 $— $294,000Fairfax Term Loan — 222,000 — 222,0002018 Notes 79,028 — — 79,0282022 Notes 35,260 — — 35,260Other fair value measurementsDuring 2017 and 2016, we impaired $5.2 million and $4.9 million, respectively, of our investment in a midstream company in the East Texas andNorth Louisiana regions that we account for under the cost method of accounting. The estimated fair value of our cost method investment was determinedbased on transaction multiples for similar companies. During 2016, we also impaired $4.7 million of our equity method investment in a midstream companyin the Appalachia region and $1.7 million of our equity method investment in OPCO. The estimated fair value of our equity method investment in amidstream company in the Appalachia region was determined based on transaction multiples of peer companies and a discounted cash flow model from ourinternally generated oil and natural gas reserves for the related properties. The estimated fair value of OPCO was determined based on trading metrics of peercompanies. The impairments of our cost and equity method investments were primarily a result of limited development activity in the regions. Theimpairments were recorded to reduce the carrying values to the fair values and were considered to be Level 3 within the fair value hierarchy.As discussed in "Note 3. Acquisitions, divestitures and other significant events", we recorded a $23.2 million loss in "Other operating items" in ourConsolidated Statements of Operations during 2016 and a corresponding credit to our "Proved developed and undeveloped oil and natural gas properties" inour balance sheet related to the settlement of litigation with a joint venture partner in the Eagle Ford shale. The fair market value of the properties transferredpursuant to the settlement was determined using a discounted cash flow model of the estimated reserves. The estimated quantities of reserves utilizedassumptions based on our internal geological, engineering and financial data. We utilized NYMEX forward strip prices to value the reserves, then appliedvarious discount rates depending on the classification of reserves and other risk characteristics. The fair value measurements utilized included significantunobservable inputs that are considered to be Level 3 within the fair value103Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.hierarchy. These unobservable inputs include management's estimates of reserve quantities, commodity prices, operating costs, development costs, discountfactors and other risk factors applied to the future cash flows.As discussed in "Note 2. Summary of significant accounting policies", we assess our unproved oil and natural gas properties for potential impairmentdue to an other than temporary trend that would negatively impact the fair value. During the year ended December 31, 2015, we impaired approximately$88.1 million of unproved properties to reduce the carrying value to the fair value. These impairment charges were transferred to the depletable portion of thefull cost pool. We calculated the estimated fair value of our unproved properties based on the average cost per undeveloped acre or the discounted cash flowmodels from our internally generated oil and natural gas reserves as of December 31, 2015. The pricing utilized in the discounted cash flow models was basedon NYMEX futures, adjusted for basis differentials. Our oil and natural gas properties were further discounted based on the classification of the underlyingreserves and management's assessment of recoverability. The fair value measurements utilized included significant unobservable inputs that were consideredto be Level 3 within the fair value hierarchy. These unobservable inputs include management's estimates of reserve quantities, commodity prices, operatingcosts, development costs, discount factors and other risk factors applied to the future cash flows. The average cost per undeveloped acre was based on recentcomparable market transactions in each region.7.Environmental regulationVarious federal, state and local laws and regulations covering discharge of materials into the environment, or otherwise relating to the protection of theenvironment, may affect our operations and the costs of our oil and natural gas exploitation, development and production operations. We do not anticipatethat we will be required in the foreseeable future to expend amounts material in relation to the financial statements taken as a whole by reason ofenvironmental laws and regulations. Because these laws and regulations are constantly being changed, we are unable to predict the conditions and otherfactors over which we do not exercise control that may give rise to environmental liabilities affecting us.8.Commitments and contingenciesThe following table presents our future minimum obligations under our commercial commitments as of December 31, 2017. The commitments do notinclude those of our equity method investments.(in thousands) Gathering and firmtransportation services (1) Other fixed commitments Drilling contracts Operating leases and other Total2018 $87,621 $3,222 $1,138 $3,760 $95,7412019 47,541 2,415 — 3,149 53,1052020 46,463 1,949 — 1,622 50,0342021 33,306 1,601 — 36 34,9432022 33,306 — — — 33,306Thereafter 94,443 — — — 94,443Total $342,680 $9,187 $1,138 $8,567 $361,572(1)The commitments under our firm transportation agreement with Regency have been excluded from the above totals. See the discussion below for more details regardingthis agreement.Gathering and firm transportation servicesWe have entered into firm transportation and gathering agreements with pipeline companies to facilitate sales from our East Texas and NorthLouisiana production. Gathering and firm transportation services presented in the tables within this footnote represent our gross commitments under thesecontracts, and a portion of these costs will be incurred by working interest and other owners. We report these costs as gathering and transportation expenses oras a reduction in total sales price received from the purchaser. In addition, our variable rate firm transportation and gathering agreements do not have aminimum volume commitment and are not included in the tables within this footnote. As such, our gathering and firm transportation services presented in thetable above may not be representative of the amounts reported as gathering and transportation expenses in our Consolidated Financial Statements.At December 31, 2017, our firm transportation and gathering agreements covered the following gross volumes of natural gas:(in Bcf) Firm transportation services (1) Gathering services2018 183 1002019 183 —2020 180 —2021 146 —2022 146 —Thereafter 413 —Total 1,251 100(1)The commitments under our firm transportation agreement with Regency have been excluded from the above totals. See the discussion below for more details regardingthis agreement.On January 18, 2018, the Company and the Filings Subsidiaries filed motions to reject certain executory contracts as permitted under the BankruptcyCode. This included certain of our sales, gathering and transportation agreements included as commitments as of December 31, 2017. See further discussionof the rejection of these executory contracts in "Note 17. Subsequent events".Enterprise and Acadian contract litigationSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.During the third quarter of 2016, we terminated our sales and transportation contracts with Enterprise Products Operating LLC (“Enterprise”) andAcadian Gas Pipeline System (“Acadian”), respectively. We transported natural gas produced from our operated wells in North Louisiana through Acadian,and Enterprise was a purchaser of certain volumes of our natural gas, until we terminated the contracts. Enterprise and Acadian are part of the corporate familyof Enterprise Products Partners L.P. (“EPD”). Acadian is an indirect, wholly-owned subsidiary of EPD that owns and operates the Acadian natural gas pipelinesystem. The agreement with Acadian provided for the firm transportation of 150,000 Mmbtu/day and 175,000 Mmbtu/day of natural gas at reservation fees of$0.25 and $0.20, respectively. In addition, the sales contract with Enterprise contemplated that we could, subject to certain limitations and exclusions, sell75,000 Mmbtu/day of natural gas at a $0.25 reduction from market index prices. The primary term for these contracts had been through October 31, 2025.The fees described represent our gross commitments and a portion of these costs is allocated to working interest and other owners. The Acadian firmtransportation agreement is accounted for as gathering and transportation expenses, and the Enterprise sales contract is accounted for as a reduction in thetotal sales price within revenues.Under the parties’ sales and transportation agreements, Enterprise owed us for July 2016 natural gas sales, and we owed Acadian for July 2016transportation fees. The amount owed to us by Enterprise exceeded the amount owed by us to Acadian. We notified Enterprise in writing of its failure to payand gave Enterprise opportunity to cure. When Enterprise failed to cure, we gave written notice to Enterprise and Acadian that we were terminating the salesand transportation agreements. Enterprise and Acadian subsequently filed an action in Harris County, Texas, against us alleging that we could not terminatethe parties’ agreements despite Enterprise's uncured payment default under the natural gas sales agreement, and further alleged that we were in breach of thefirm transportation agreements. On October 17, 2016, we filed a counterclaim asserting that Enterprise was the breaching party because it improperlywithheld payment for natural gas we delivered to it and the amounts owed by Enterprise exceeded the amounts owed by us to Acadian. We are also seeking adeclaration that we properly terminated the contracts with Enterprise and Acadian. EPD subsequently joined two of our officers, Harold Hickey and SteveEstes, asserting breach of fiduciary duty claims and thereafter joined Bluescape asserting tortious interference with an existing contract. We have filed asummary judgment motion as to the claims against us and our officers, and the motion is pending before the court. If we prevail on the summary judgmentmotion it could be case dispositive. This case is anticipated to go to trial in the second or third quarter of 2018; however, the case is stayed due to ourChapter 11 filings. We cannot currently estimate or predict the outcome of the litigation but we plan to vigorously defend our right to terminate the contractsand to seek the amounts owed to us for delivered natural gas.We are no longer selling natural gas under the Enterprise sales contract or transporting natural gas under the Acadian firm transportation contracteffective as of the termination date. The Company is accounting for these contracts in accordance with FASB ASC 450 ("ASC 450"), Contingencies, whichstates a contingency that might result in a gain should not be reflected until it is realized or realizable. There is a rebuttable presumption that a claim subjectto litigation does not meet the criteria to be realized or realizable; therefore, the termination of these contracts will not be reflected in our financial resultsuntil the104Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.litigation is resolved. Upon resolution of the litigation, we will adjust the previously recognized amounts to reflect the outcome of the litigation. As ofDecember 31, 2017, we recorded a net liability of $43.8 million for costs subsequent to the termination of the contract in accordance with the guidancerelated to contingencies in ASC 450. The minimum obligations under these agreements are included in the tables of our commercial commitments as ofDecember 31, 2017.Regency transportation agreement defaultWe have a firm transportation agreement with Regency Intrastate Gas Systems LLC ("Regency") to transport 237,500 Mmbtu/day of natural gas at acost of $0.30 per Mmbtu until January 31, 2020. We were obligated to pay a reservation charge of $0.30 per Mmbtu if we failed to transport the minimumvolumes under the agreement. The costs under the agreement were recorded as "Gathering and transportation expenses" in our Consolidated Statement ofOperations.On October 23, 2017, we were notified of our failure to pay $2.2 million for the July 2017 charges. The contract provides that the failure to pay theentire charge when due constitutes a default. If the payment default was not fully cured to Regency’s satisfaction within 30 days written notice, Regency hasthe right to immediately accelerate the payments of the remaining reservation charges due under the contract. We have not received a notice of acceleration.We have not cured the default for July 2017 and have not remitted payment for any subsequent months.Due to our default under the contract and Regency's right to accelerate the remaining payments, we accounted for these contracts in accordance withASC 450, which states that an estimated loss from a loss contingency shall be accrued if (1) information available before the financial statements are issuedindicates that it is probable that an asset had been impaired or a liability had been incurred at the date of the financial statements, and (2) the amount of losscan be reasonably estimated. As of December 31, 2017, the unpaid amounts and remaining charges under this agreement of $67.3 million were recorded as"Revenue and royalties payable" in our Consolidated Balance Sheet. In addition to the expenses under the agreement prior to the event of default, werecorded $56.4 million related to the acceleration of the remaining charges subsequent to the event of default as "Other operating items" in our ConsolidatedStatement of Operations for the year ended December 31, 2017.Shell natural gas sales contract litigationWe had a natural gas sales agreement with Shell Energy North America (US) LP ("Shell Energy"), a subsidiary of Shell, under which we werecontractually obligated to deliver and sell to Shell Energy, and Shell Energy was contractually obligated to receive and purchase from us, natural gasproduction of 100,000 Mmbtu/day. We were to receive the product of an index price and the volumes delivered less the product of the reservation charge of$0.39 per Mmbtu and the daily contract volume. The contract was scheduled to end in November 2020.On December 22, 2017, we received notice from Shell Energy that they were exercising their right to require adequate assurance of performance fromus for the reservation charges under the contract. Shell Energy requested assurances in the form of letters of credit of approximately $44.4 million, which wasapproximately equal to the remaining reservation charges for the remaining term of the contract. We responded to the notice by stating the request for theletter of credit request was unreasonable and unjustified under the terms of the agreement. Subsequently, Shell Energy notified us that they were withholdingpayment for the purchase of natural gas for the months of November and December 2017 as a means to satisfy their demands of reasonable assurance ofperformance. Shell Energy allegedly terminated the sales contracts on December 26, 2017 as a result of the adequate assurance provision despite ourobjections to the reasonableness of their request. We ceased selling natural gas to Shell Energy in the East Texas and North Louisiana regions effective as ofthe date of their breach.On December 26, 2017, we filed a claim in Harris County, Texas seeking declaratory relief that (1) we had not undergone an event of default as definedwithin the agreement, (2) Shell Energy was in material breach of the contract, and (3) Shell Energy’s request of adequate assurance of performance was neitherreasonable, nor justified, and not in good faith under the agreement or applicable Texas law. In addition to the preceding, we are also seeking actual damages,reasonable attorneys’ fees, court costs, prejudgment and post-judgment interest at the maximum rate allowed by Texas law, and all other relief to which wemay be justly entitled. On January 26, 2018, we filed a notice of non-suit in Harris County District Court. Concurrently with filing the notice of non-suit inthe county court, we filed an adversary proceeding against Shell Energy in the Chapter 11 Cases.As of December 31, 2017, we recorded a receivable of approximately $33.4 million related to the sales of natural gas to Shell Energy in East Texas andNorth Louisiana for the months of November and December 2017. As of December 31, 2017, we are withholding $16.8 million in revenues payable to Shellto offset our exposure until the litigation is resolved. The revenues payable may increase in subsequent months due to the natural gas marketed on behalf ofShell's ownership interests in our operated wells. We plan to adamantly assert our right to terminate the contract as a result of Shell Energy's breach and105Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.demand payment for the natural gas sales during November and December 2017. Due to the uncertainty surrounding the outcome of the litigation, we are notable to reasonably estimate a potential loss, if any, at this time. The minimum obligations under this agreement are included in the tables of our commercialcommitments as of December 31, 2017.Other commitmentsWe lease our offices and certain equipment. Our rental expenses were approximately $2.3 million, $2.6 million and $3.4 million for the years endedDecember 31, 2017, 2016 and 2015, respectively. We have also entered into drilling rig contracts primarily to develop our assets in the East Texas and NorthLouisiana regions. The actual drilling costs under these contracts will be incurred by working interest owners in the development of the related properties.These contracts are short-term in nature and are dependent on our planned drilling program.Our other fixed commitments primarily consist of marketing contracts in which we are obligated to pay the buyer a fee if we fail to deliver minimumquantities of natural gas.In the ordinary course of business, we are periodically a party to lawsuits. From time to time, oil and natural gas producers, including EXCO, have beennamed in various lawsuits alleging underpayment of royalties and the allocation of production costs in connection with oil and natural gas sold. We havereserved our estimated exposure and do not believe it was material to our current, or future, financial position or results of operations.We believe that we have properly reflected any potential exposure in our financial position when determined to be both probable and estimable.9.Employee benefit plansWe sponsor a 401(k) plan for our employees and matched 100% of employee contributions during 2015. Our matching program was suspended during2016 in response to depressed oil and natural gas prices which have negatively impacted our business and operations. The Company reinstated its matchingprogram effective January 1, 2017 in which it matched 100% of employee contributions up to a maximum of 3% of each employee's pay. Effective January 1,2018, the Company increased its matching contribution up to a maximum of 4% of each employee's pay. Our matching contributions were $0.6 million and$5.2 million for the years ended December 31, 2017 and 2015, respectively.10.Earnings per shareThe following table presents the basic and diluted earnings (loss) per share computations for the years ended December 31, 2017, 2016 and 2015: Year Ended December 31,(in thousands, except per share data) 2017 2016 2015Basic net income (loss) per common share: Net income (loss) $24,362 $(225,258) $(1,192,381)Weighted average common shares outstanding 21,288 18,630 18,241Net income (loss) per basic common share $1.14 $(12.09) $(65.37)Diluted net income (loss) per common share: Net income (loss) $24,362 $(225,258) $(1,192,381)Weighted average common shares outstanding 21,288 18,630 18,241Dilutive effect of: Stock options — — —Restricted shares and restricted share units — — —Warrants — — —Weighted average common shares and common share equivalents outstanding 21,288 18,630 18,241Net income (loss) per diluted common share $1.14 $(12.09) $(65.37)Basic net income (loss) per common share is based on the weighted average number of common shares outstanding during the period. In addition, theCommitment Fee and Amendment Fee Warrants, which represent the right to purchase our common shares at an exercise price of $0.01, are included in ourweighted average common shares outstanding and used in the106Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.computation of our basic net income (loss) per common share. On January 16, 2018, affiliates of Fairfax surrendered all of their rights to the Commitment Feeand Amendment Fee Warrants at an exercise price of $0.01. See "Note 13. Related party transactions" for additional information on the warrants issued toFairfax.Diluted net income (loss) per common share for years December 31, 2017, 2016 and 2015 is computed in the same manner as basic net income (loss)per share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which include stock options, restricted shareunits, restricted share awards, Financing Warrants, and ESAS Warrants, whether exercisable or not. The computation of diluted EPS excluded 12,907,872;5,097,538; and 2,636,279 antidilutive common share equivalents for the years ended December 31, 2017, 2016 and 2015, respectively. The antidilutivecommon share equivalents for the year ended December 31, 2017 primarily related to the Financing Warrants. The antidilutive common share equivalents forthe year ended December 31, 2016 and 2015 primarily related to the ESAS Warrants. On November 9, 2017, the ESAS Warrants were forfeited as a result ofsuspension of the services and investment agreement with ESAS. See "Note 11. Equity-based and other incentive-based compensation" for additionalinformation on the warrants issued to ESAS.On January 16, 2018, affiliates of Fairfax surrendered all of their rights to the Commitment Fee, Amendment Fee and Financing Warrants. See "Note 13.Related party transactions" for additional information on the Financing Warrants issued to Fairfax.11.Equity-based and other incentive-based compensationShare-based compensationDescription of planOur 2005 Incentive Plan is a shareholder-approved plan authorizing the issuance of up to 3,033,333 restricted shares, restricted share units and stockoptions. As of December 31, 2017 and 2016, there were 1,140,543 and 952,918 shares, respectively, available for issuance under the 2005 Incentive Plan.Option grants and restricted share grants count as one share and 1.74 shares, respectively, against the total number of shares available for grant. The holders ofrestricted shares, excluding restricted share units ("RSU") discussed below, have voting rights, and upon vesting, the right to receive all accrued and unpaiddividends.We believe it is highly likely that our existing common shares and share-based compensation will be canceled at the conclusion of our Chapter 11proceedings and holders will be entitled to a limited recovery, if any. See "Item 1A. Risk Factors" for additional information.Stock optionsAs of December 31, 2017, we had 108,578 stock options outstanding and exercisable with exercise prices ranging from $74.70 to $405.00 per share.We did not grant any stock options during the years ended December 31, 2017, 2016 or 2015. Our outstanding stock option expiration dates range from fiveto ten years following the date of grant and have a weighted average remaining life of 3.24 years.Service-based restricted share awardsOur service-based restricted share awards are valued at the closing price of our common shares on the date of grant and vest over a range of one to fiveyears. A summary of our service-based restricted share activity for the year ended December 31, 2017 is as follows: Shares Weighted average grant date fair value pershare Non-vested shares outstanding at December 31, 2016 145,907 $18.99 Granted 39,384 9.78 Vested (117,781) 17.94 Forfeited (30,908) 15.10 Non-vested shares outstanding at December 31, 2017 36,602 $15.75107Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Market-based restricted share awards Certain RSU's granted to our officers and certain employees have vesting percentages between 0% and 200% depending on EXCO's total shareholderreturn in comparison to an identified peer group. Our market-based restricted share units are valued on the date of grant and vest over a range of three years,subject to the achievement of certain criteria. Total compensation expense is recognized over the vesting period using the straight-line method.The Company has discretion to convert certain vested awarded units, if any, into a cash payment equal to the fair market value of a share of commonstock, multiplied by the number of vested units, or the number of whole shares of common stock equal to the number of vested units, if any. These RSUs metthe criteria for equity classification per ASC 718.The grant date fair values of our market-based restricted share awards and restricted share units were determined using a Monte Carlo model which usescompany-specific inputs to generate different stock price paths. The assumptions used in the Monte Carlo model for the RSUs granted in 2016 are as follows:Assumption 2016Risk-free rate of return 0.45 - 0.71 %Volatility 119.83 %Dividend yield 0.00 %A summary of our market-based restricted share activity for RSUs during the year ended December 31, 2017 is as follows: Shares Weighted average grantdate fair value per share Non-vested shares/units outstanding at December 31, 2016 337,331 $27.83Granted — —Vested — —Forfeited (87,339) 21.74Non-vested shares/units outstanding at December 31, 2017 249,992 $29.96ESAS WarrantsOn September 8, 2015, EXCO issued warrants to ESAS as an additional performance incentive for services performed under a services and investmentagreement. The ESAS Warrants were issued in four tranches to purchase an aggregate of 5,333,335 common shares, subject to certain time-based vestingcriteria and EXCO's total shareholder return in comparison to an identified peer group. See further discussion of the ESAS Warrants in "Note 13. Related partytransactions".Equity-based compensation costsAll of our stock options, restricted shares and certain RSUs are accounted for in accordance with ASC 718 and are classified as equity. As required byASC 718, the granting of options and awards to our employees under the 2005 Incentive Plan are share-based payment transactions and are to be treated ascompensation expense by us with a corresponding increase to additional paid-in capital.Total share-based compensation to employees to be recognized on unvested options, restricted share awards and RSUs as of December 31, 2017 was$3.2 million and will be recognized over a weighted average period of 1.4 years.The measurement of the ESAS Warrants was accounted for in accordance with ASC 505-50, which required the ESAS Warrants to be re-measured eachinterim reporting period and an adjustment was recorded in the statement of operations within equity-based compensation expense. Concurrently with thesuspension of the services and investment agreement with ESAS, on November 9, 2017, the ESAS Warrants were forfeited and canceled and previouslyrecognized compensation costs were reversed. For the years ended December 31, 2017, 2016 and 2015, equity-based compensation related to the ESASWarrants was income of $14.5 million and expense of $11.3 million and $3.2 million, respectively.108Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.The following is a reconciliation of our compensation expense for the years ended December 31, 2017, 2016 and 2015: Year Ended December 31,(in thousands) 2017 2016 2015Equity-based compensation expense (1) $(11,430) $14,778 $7,198Equity-based compensation capitalized 1,000 752 3,428Total equity-based compensation $(10,430) $15,530 $10,626(1)Equity-based compensation expense includes share-based compensation to employees and equity-based compensation for ESAS Warrants.We did not recognize a tax benefit attributable to our equity-based compensation for the years ended December 31, 2017, 2016 and 2015.Key Employee Incentive Plan, Key Employee Retention Plan, and Prepaid Retention PlansIn connection with our review of strategic alternatives during late 2017, the Compensation Committee of the Board of Directors (“CompensationCommittee”) determined that (i) normal annual and long-term incentive cycles are likely to be ineffective due to our ongoing strategic restructuring effortsand (ii) the use of equity compensation is currently ineffective and inefficient. As a result, the Compensation Committee and the Company restructured ourincentive plans to retain employees and align the interests of employees with our stakeholders. We implemented the following changes to our compensationplans:•Termination of the 2017 Management Incentive Plan - We terminated the 2017 Management Incentive Plan and made pro-rated incentivepayments based on the achievement of performance goals as of June 30, 2017. The payments of $1.1 million were made in cash.•Adoption of the KEIP and KERP - We adopted two new cash-based incentive programs, including the Key Employee Incentive Plan ("KEIP") forcertain officers and Key Employee Retention Plan ("KERP") for employees. The payout of the KEIP is dependent on the achievement of certainperformance goals, including production, general and administrative expenses, lease operating expenses, and EBITDA. The payout of the KERPwas dependent on the achievement of these performance measures and a fixed percentage of the employees' salary for the first two quarters of theplan until it was converted to be solely based on a fixed percentage of the employees' salary. The initial term under each of these plans is from July1, 2017 to June 30, 2018. We incurred $4.8 million in general and administrative expenses related to these plans during 2017. The motion toconsider the KERP was approved by the Court on February 22, 2018. The approval of the KEIP for the period subsequent to the petition dateremains subject to approval as part of the Chapter 11 Cases. As a result, the terms and amounts related to the KEIP could materially change if wereceive objections from the Court or our creditors. The KEIP and KERP may be extended beyond the initial term at the discretion of theCompensation Committee or the Company, which would be subject to further approval as part of the Chapter 11 Cases.•Retention Bonus Agreements - We entered into retention bonus agreements with certain key officers and employees, which resulted in payments of$7.9 million during 2017. In the event a recipient of a retention bonus voluntarily terminates his or her employment without Good Reason (asdefined in each Retention Bonus Agreement), or the Company terminates such recipient’s employment for Cause (as defined in each RetentionBonus Agreement), in either case, before either December 31, 2018 or March 31, 2019 (depending on the agreement with the officer or employee),then such recipient will be required to promptly repay the retention bonus. We recognized $1.4 million of general and administrative expensesrelated to these retention bonuses during 2017 and the remainder will be recognized over the remaining retention period.•Discontinuation of equity incentive grants - We have discontinued the grant of share-based compensation to officers and employees until thecompletion of a restructuring. As a result, there were no grants of share-based compensation during 2017. The adoption of the KEIP, KERP andretention bonuses were intended to replace all existing cash-based bonus and equity-based compensation programs.109Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.12.Income taxesThe income tax provision attributable to our income (loss) before income taxes for the years ended December 31, 2017, 2016 and 2015, consisted ofthe following: Year ended December 31,(in thousands) 2017 2016 (1) 2015Current: Federal $(1,420) $— $—State — — —Total current income tax (benefit) $(1,420) $— $— Deferred: Federal $528,886 $(72,020) $(414,834)State (1,496) (7,637) (45,009)Valuation allowance (525,674) 82,459 459,843Total deferred income tax (benefit) 1,716 2,802 —Total income tax (benefit) $296 $2,802 $—(1)We made certain revisions between components of the reconciliation of our income tax provision for the year ended December 31, 2016. These revisions were deemed tobe an immaterial correction of an error and did not affect our net deferred tax assets or liabilities or income tax expense.On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act ("Tax Act") which, among other things, lowered the U.S. Federal tax ratefrom 35% to 21%, repealed the corporate alternative minimum tax, and provided for a refund of previously accrued alternative minimum tax credits. Wereflected the impact of this rate on our deferred tax assets and liabilities at December 31, 2017, as it is required to reflect the change in the period in which thelaw is enacted. The Tax Act also repealed the corporate alternative minimum tax for tax years beginning after January 1, 2018 and provided that prioralternative minimum tax credits would be refundable. We have credits that are expected to be refunded between 2018 and 2020 as a result of the Tax Act andmonetization opportunities under current law in 2017. In addition, the Tax Act limits the amount taxpayers are able to deduct for net operating losscarryforwards ("NOLs") generated in taxable years beginning after December 31, 2017 to 80% of the taxpayer’s taxable income. The law also generallyrepeals all carrybacks for losses generated in taxable years ending after December 31, 2017. However, any NOLs generated in taxable years ending afterDecember 31, 2017 can be carried forward indefinitely. On December 22, 2017, the SEC issued Staff Accounting Bulletin No. 118, which provides a one-yearmeasurement period from a registrant's reporting period that includes the Tax Act's enactment date to allow the registrant sufficient time to obtain, prepareand analyze information to complete the required accounting under ASC 740. We are still analyzing certain aspects of the Tax Act, which could potentiallyaffect the measurement of our income tax balances and future income tax expense or benefit. The ultimate impact of the Tax Act may differ from the estimatesprovided herein, possibly materially, due to additional regulatory guidance, changes in interpretations and assumptions, and other actions as a result of theTax Act.We have NOLs for U.S. income tax purposes that have been generated from our operations. Our NOLs are scheduled to expire if not utilized between2028 and 2037. As a result of the repurchase of a portion of our senior unsecured notes during 2015 and 2016, we had cancellation of debt income for taxpurposes. We reduced our NOLs by the amount of cancellation of debt income of approximately $86.6 million, $125.8 million and $538.0 million during2017, 2016 and 2015, respectively.The utilization of our NOLs to offset taxable income in future periods may be limited if we undergo an ownership change based on the criteria inSection 382 of the Internal Revenue Code. Generally, an ownership change occurs for Section 382 purposes when the percentage of stock held by one ormore five-percent shareholders increases by more than 50 percentage points over the lowest stock ownership held by such shareholders on any testing datewithin a three-year period. See further discussion of the potential limitations on the utilization of our net operating losses as part of "Item 1A. Risk Factors".The Internal Revenue Code permits the exclusion of cancellation of debt income from taxable income if the discharge occurs during a Chapter 11 case. If thisoccurs, the amount of cancellation of debt income would reduce a company's tax attributes unless it is offset by NOLs. The NOLs that are available to offsetcancellation of debt income in a Chapter 11 case are not limited by110Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Section 382 of the Internal Revenue Code. NOLs available for utilization as of December 31, 2017 were approximately $2.1 billion.Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reportingpurposes and the amounts used for income tax purposes. Significant components of our deferred tax liabilities and assets are as follows:(in thousands) December 31, 2017 December 31, 2016 (1)Deferred tax assets: Net operating loss and AMT credits carryforwards $548,701 $767,236Oil and natural gas properties, gathering assets, and equipment 236,601 428,056Debt restructuring 3,978 99,934Other 54,487 73,923Total deferred tax assets before valuation allowance 843,767 1,369,149Valuation allowance (843,480) (1,369,149)Total deferred tax assets 287 —Deferred tax liabilities: Goodwill $(4,518) $(2,802)Derivative financial instruments (287) —Total deferred tax liabilities (4,805) (2,802)Net deferred tax assets (liabilities) $(4,518) $(2,802)(1)We made certain revisions between components of our non-current deferred tax assets as of December 31, 2016. As a result, our deferred tax assets and valuationallowance increased by $0.8 million. These revisions were deemed to be an immaterial correction of an error and did not affect our net deferred tax assets or liabilities orincome tax expense.As previously discussed, we reflected the impact of the change in the tax rate as a result of the Tax Act on our deferred tax assets and liabilities atDecember 31, 2017. During the years ended 2017, 2016 and 2015, we recognized a full valuation allowance against our net deferred tax assets.A reconciliation of our income tax provision (benefit) computed by applying the statutory United States federal income tax rate to our income (loss)before income taxes for the years ended December 31, 2017, 2016 and 2015 is presented in the following table: Year Ended December 31,(in thousands) 2017 2016 (1) 2015Federal income taxes (benefit) provision at statutory rate of 35% $8,630 $(77,860) $(417,333)Increases (reductions) resulting from: Adjustments to the valuation allowance (525,674) 82,459 459,843Non-deductible compensation 3,206 5,019 2,399State taxes net of federal benefit (1,496) (7,637) (45,009)Federal and state tax rate change 421,610 — —Non-deductible interest 149,577 — —Non-taxable gain on warrants (55,716) — —Other 159 821 100Total income tax provision $296 $2,802 $—(1)We made certain revisions between components of the reconciliation of our income tax provision for the year ended December 31, 2016. These revisions were deemed tobe an immaterial correction of an error and did not affect our net deferred tax assets or liabilities or income tax expense.During the year ended December 31, 2017, we recognized a current income tax benefit of $1.4 million due to refunds for alternative minimum taxcredits. During the years ended 2017 and 2016, we recognized deferred income tax expense of $1.7111Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.million and $2.8 million related to a deferred tax liability for tax deductible goodwill. During the years ended 2017 and 2016, the book basis of goodwillexceeded the tax basis that caused the previous book and tax basis differences to change from a deferred tax asset to a deferred tax liability. The deferred taxliability related to goodwill is considered to have an indefinite life based on the nature of the underlying asset and cannot be offset under GAAP with adeferred tax asset with a definite life, such as NOLs. However, the deferred income tax expense is not expected to result in cash payments of income taxes inthe foreseeable future. We did not recognize any liabilities for unrecognized tax benefits. As of December 31, 2017, 2016 and 2015, our policy is to recognize interest relatedto unrecognized tax benefits of interest expense and penalties in operating expenses. We have not accrued any interest or penalties relating to unrecognizedtax benefits in the Consolidated Financial Statements. We file a corporate consolidated income tax return for U.S. federal income tax purposes and file income tax returns in various states. With fewexceptions, we are no longer subject to U.S. federal and state and local examinations by tax authorities for years before 2008.13.Related party transactionsOPCO and Appalachia Midstream JVOPCO serves as the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis. We did not advance any funds toOPCO during the years ended December 31, 2017, 2016 or 2015. OPCO may distribute any excess cash equally between us and Shell when its operating cashflows are sufficient to meet its capital requirements. There are service agreements between us and OPCO whereby we provide administrative and technicalservices for which we are reimbursed. For the years ended December 31, 2017, 2016 and 2015 these transactions included the following: Year Ended December 31,(in thousands) 2017 2016 2015Amounts received from OPCO 6,596 15,016 30,577As of December 31, 2017 and 2016, the amounts owed under the service agreements were as follows:(in thousands) December 31, 2017 December 31, 2016Amounts due to EXCO (1) $587 $618Amounts due from EXCO (2) 3,726 13,624(1)Amounts due to us consist of receivables for services performed on behalf of OPCO. These amounts are recorded in "Accounts receivable, net — Other" on ourConsolidated Balance Sheets.(2)Any amounts we owe to OPCO are netted against the advance until the advances are utilized. If the advances are fully utilized, we record amounts owed in "Accountspayable and accrued liabilities" on our Consolidated Balance Sheets.As of December 31, 2017, we owned a 50% interest in an entity that owns and operates midstream assets in the Appalachia region ("AppalachiaMidstream JV"). On October 12, 2017, EXCO received a $6.0 million cash distribution from Appalachia Midstream JV.ESASOn March 31, 2015, we entered into a services and investment agreement with ESAS, a wholly owned subsidiary of an affiliate of Bluescape. C. JohnWilder, Executive Chairman of Bluescape, was the Executive Chairman of our Board of Directors until his resignation on November 9, 2017, and indirectlycontrols ESAS. As consideration for the services provided under the agreement, EXCO paid ESAS a monthly fee of $300,000 and an annual incentivepayment of up to $2.4 million per year that was based on EXCO’s common share price achieving certain performance hurdles as compared to a peer group.The monthly fees were held in escrow until one year following the closing of the agreement and reported as "Restricted cash" on our Consolidated BalanceSheets. As an additional performance incentive under the services and investment agreement, EXCO issued ESAS Warrants in four tranches to purchase anaggregate of 5,333,335 common shares, subject to the satisfaction of certain performance criteria, at exercise prices ranging from $41.25 per share to $150.00per share. The number of shares and exercise prices have been adjusted to reflect the reverse share-split that occurred on June 2, 2017.112Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.The payments to ESAS as part of the services and investment agreement were $3.4 million and $8.4 million during 2017 and 2016, respectively.Amounts paid to ESAS in 2017 consisted of the monthly fees through the suspension of the contract in November 9, 2017. Amounts paid to ESAS in 2016consisted of (i) the monthly fees including fees previously held in escrow and (ii) a $2.4 million annual incentive payment as a result of EXCO achieving aperformance rank above the 75th percentile of the peer group.On September 20, 2017, ESAS received $4.0 million and $1.8 million of PIK Payments in the form of additional 1.5 Lien Notes and 1.75 Lien TermLoans, respectively, resulting in ESAS holding $74.0 million in aggregate principal amount of 1.5 Lien Notes and $49.7 million in aggregate principalamount of 1.75 Lien Term Loans as of December 31, 2017. During the year ended December 31, 2017, ESAS also received $1.2 million of cash interestpayments on the Exchange Term Loan and 192,609 of PIK Shares under the 1.75 Lien Term Loans. In addition, ESAS holds Financing Warrants representingthe right to purchase an aggregate of 5,017,922 common shares at an exercise price equal to $13.95 per share. ESAS received a consent fee of $1.6 million incash for exchanging its interest in the Exchange Term Loan, and a commitment fee of $2.1 million in cash in connection with the issuance of the 1.5 LienNotes.On November 9, 2017, we entered into an agreement with ESAS pursuant to which, among other things: (i) the services and investment agreement withESAS, dated as of March 31, 2015, was suspended such that, during the suspension period and subject to the terms and conditions of the agreement: (a) ESASis not required to provide any services to us, (b) we are not required to make any payments to ESAS with respect to the suspension period and (c) ESAS doesnot have the right to nominate a member to the Company’s Board of Directors; and (ii) the ESAS Warrants were forfeited and canceled and we have no furtherobligations under the ESAS Warrants.On January 22, 2018, we closed the DIP Credit Agreement with lenders including affiliates of Bluescape. See "Note 17. Subsequent events" furtherdiscussion of the DIP Credit Agreement.FairfaxSamuel Mitchell serves as a Managing Director of Hamblin Watsa Investment Counsel Ltd. ("Hamblin Watsa"), the investment manager of Fairfax andcertain affiliates thereof. Samuel Mitchell was a member of our Board of Directors until his resignation on September 20, 2017. On September 20, 2017,certain affiliates of Fairfax received $8.5 million and $15.8 million of PIK Payments in the form of additional 1.5 Lien Notes and 1.75 Lien Term Loans,respectively, resulting in Fairfax holding, directly or indirectly, $159.5 million in aggregate principal amount of 1.5 Lien Notes and $427.9 million inaggregate principal amount of 1.75 Lien Term Loans as of December 31, 2017. During the year ended December 31, 2017, Fairfax also received $10.6 millionof cash interest payments on the Fairfax Term Loan and the Exchange Term Loan and 1,657,330 of PIK Shares under the 1.75 Lien Term Loans. In addition,Fairfax holds Financing Warrants representing the right to purchase an aggregate of 10,824,377 common shares at an exercise price equal to $13.95 per share,Commitment Fee Warrants representing the right to purchase an aggregate of 431,433 common shares at an exercise price equal to $0.01 per share andAmendment Fee Warrants representing the right to purchase an aggregate of 1,294,143 common shares at an exercise price equal to $0.01 per share. OnJanuary 16, 2018, affiliates of Fairfax surrendered all of their rights in the 2017 Warrants.On January 22, 2018, we closed the DIP Credit Agreement with lenders including affiliates of Fairfax. See "Note 17. Subsequent events" furtherdiscussion of the DIP Credit Agreement.OaktreeB. James Ford serves as a Senior Advisor of Oaktree, and was a member of our Board of Directors until his resignation on September 20, 2017. OnSeptember 20, 2017, Oaktree received $2.2 million of PIK Payments in the form of additional 1.5 Lien Notes resulting in certain affiliates of Oaktree holding,directly or indirectly, $41.7 million in aggregate principal amount of 1.5 Lien Notes as of December 31, 2017. In addition, certain affiliates of Oaktree holdFinancing Warrants representing the right to purchase an aggregate of 2,831,542 common shares at an exercise price equal to $13.95 per share. Oaktree alsoreceived a commitment fee of $1.2 million in cash in connection with the issuance of the 1.5 Lien Notes.113Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.14.Condensed consolidating financial statementsAs of December 31, 2017, the majority of EXCO’s subsidiaries were guarantors under the EXCO Resources Credit Agreement, the indenture governingthe 1.5 Lien Notes, the credit agreement governing the 1.75 Lien Term Loans, the credit agreement governing the Second Lien Term Loans, and theindentures governing the 2018 Notes and 2022 Notes. The DIP Credit Agreement, entered into on January 22, 2018, is guaranteed by the same subsidiaries asthe EXCO Resources Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes. All of our unrestrictedsubsidiaries under the 1.5 Lien Notes, 1.75 Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes are considered non-guarantorsubsidiaries.Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The EXCOResources Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans, 2018 Notes and 2022 Notes, which were issued by EXCO Resources, Inc., are jointly andseverally guaranteed by substantially all of our subsidiaries (referred to as Guarantor Subsidiaries). For purposes of this footnote, EXCO Resources, Inc. isreferred to as Resources to distinguish it from the Guarantor Subsidiaries. Each of the Guarantor Subsidiaries is a 100% owned subsidiary of Resources andthe guarantees are unconditional as they relate to the assets of the Guarantor Subsidiaries.The following financial information presents consolidating financial statements, which include:•Resources;•the Guarantor Subsidiaries;•the Non-Guarantor Subsidiaries;•elimination entries necessary to consolidate Resources, the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries; and•EXCO on a consolidated basis.Investments in subsidiaries are accounted for using the equity method of accounting for the disclosures within this footnote. The financial informationfor the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries is presented on a combined basis. The elimination entries primarily eliminate investmentsin subsidiaries and intercompany balances and transactions.114Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO RESOURCES, INC.CONDENSED CONSOLIDATING BALANCE SHEETDecember 31, 2017 (in thousands) Resources GuarantorSubsidiaries Non-GuarantorSubsidiaries Eliminations ConsolidatedAssets Current assets: Cash and cash equivalents $49,170 $(9,573) $— $— $39,597Restricted cash — 15,271 — — 15,271Other current assets 22,697 90,265 — — 112,962Total current assets 71,867 95,963 — — 167,830Equity investments — — 14,181 — 14,181Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties and development costs notbeing amortized — 118,652 — — 118,652Proved developed and undeveloped oil and natural gas properties 333,719 2,773,847 — — 3,107,566Accumulated depletion (330,777) (2,421,534) — — (2,752,311)Oil and natural gas properties, net 2,942 470,965 — — 473,907Other property and equipment, net and other non-current assets 892 20,382 — — 21,274Investments in and advances to affiliates, net 466,055 — — (466,055) —Goodwill 13,293 149,862 — — 163,155Total assets $555,049 $737,172 $14,181 $(466,055) $840,347Liabilities and shareholders' equity Current maturities of long-term debt $1,362,500 $— $— $— $1,362,500Other current liabilities 32,280 272,190 — — 304,470Long-term debt — — — — —Derivative financial instruments - common share warrants 1,950 — — — 1,950Other long-term liabilities 4,518 13,108 — — 17,626Payable to parent — 2,447,586 — (2,447,586) —Total shareholders' equity (846,199) (1,995,712) 14,181 1,981,531 (846,199)Total liabilities and shareholders' equity $555,049 $737,172 $14,181 $(466,055) $840,347115Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO RESOURCES, INC.CONDENSED CONSOLIDATING BALANCE SHEETDecember 31, 2016 (in thousands) Resources GuarantorSubsidiaries Non-GuarantorSubsidiaries Eliminations ConsolidatedAssets Current assets: Cash and cash equivalents $24,610 $(15,542) $— $— $9,068Restricted cash — 11,150 — — 11,150Other current assets 6,463 83,936 — — 90,399Total current assets 31,073 79,544 — — 110,617Equity investments — — 24,365 — 24,365Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties and development costs notbeing amortized — 97,080 — — 97,080Proved developed and undeveloped oil and natural gas properties 331,823 2,608,100 — — 2,939,923Accumulated depletion (330,776) (2,371,469) — — (2,702,245)Oil and natural gas properties, net 1,047 333,711 — — 334,758Other property and equipment, net and other non-current assets 568 23,093 — — 23,661Investments in and advances to affiliates, net 430,168 — — (430,168) —Deferred financing costs, net 4,376 — — — 4,376Derivative financial instruments - commodity derivatives 482 — — — 482Goodwill 13,293 149,862 — — 163,155Total assets $481,007 $586,210 $24,365 $(430,168) $661,414Liabilities and shareholders' equity Current maturities of long-term debt $50,000 $— $— $— $50,000Other current liabilities 40,671 167,692 — — 208,363Long-term debt 1,258,538 — — — 1,258,538Other long-term liabilities 3,704 12,715 — — 16,419Payable to parent — 2,337,585 — (2,337,585) —Total shareholders' equity (871,906) (1,931,782) 24,365 1,907,417 (871,906)Total liabilities and shareholders' equity $481,007 $586,210 $24,365 $(430,168) $661,414 116Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO RESOURCES, INC.CONDENSED CONSOLIDATING STATEMENT OF OPERATIONSFor the year ended December 31, 2017(in thousands) Resources GuarantorSubsidiaries Non-GuarantorSubsidiaries Eliminations ConsolidatedRevenues: Oil and natural gas $— $258,830 $— $— $258,830Purchased natural gas and marketing — 24,816 — — 24,816Total revenues — 283,646 — — 283,646Costs and expenses: Oil and natural gas production — 48,142 — — 48,142Gathering and transportation — 111,427 — — 111,427Purchased natural gas — 23,400 — — 23,400Depletion, depreciation and amortization 298 50,742 — — 51,040Impairment of oil and natural gas properties — — — — —Accretion of discount on asset retirement obligations — 874 — — 874General and administrative (30,224) 60,389 — — 30,165Other operating items 553 58,601 — — 59,154 Total costs and expenses (29,373) 353,575 — — 324,202Operating income (loss) 29,373 (69,929) — — (40,556)Other income (expense): Interest expense, net (108,173) (2) — — (108,175)Gain on derivative financial instruments - commodity derivatives 24,732 — — — 24,732Gain on derivative financial instruments - common share warrants 159,190 — — — 159,190Loss on restructuring of debt (6,380) — — — (6,380)Other income 30 1 — — 31Equity loss — — (4,184) — (4,184)Net loss from consolidated subsidiaries (74,114) — — 74,114 — Total other income (expense) (4,715) (1) (4,184) 74,114 65,214Income (loss) before income taxes 24,658 (69,930) (4,184) 74,114 24,658Income tax expense 296 — — — 296Net income (loss) $24,362 $(69,930) $(4,184) $74,114 $24,362117Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO RESOURCES, INC.CONDENSED CONSOLIDATING STATEMENT OF OPERATIONSFor the year ended December 31, 2016(in thousands) Resources GuarantorSubsidiaries Non-GuarantorSubsidiaries Eliminations ConsolidatedRevenues: Oil and natural gas $— $248,649 $— $— $248,649Purchased natural gas and marketing — 22,352 — — 22,352Total revenues — 271,001 — — 271,001Costs and expenses: Oil and natural gas production 4 49,985 — — 49,989Gathering and transportation — 106,460 — — 106,460Purchased natural gas — 23,557 — — 23,557Depletion, depreciation and amortization 381 75,601 — — 75,982Impairment of oil and natural gas properties 838 159,975 — — 160,813Accretion of discount on asset retirement obligations — 2,210 — — 2,210General and administrative (11,254) 59,954 — — 48,700Other operating items (385) 24,624 — — 24,239 Total costs and expenses (10,416) 502,366 — — 491,950Operating income (loss) 10,416 (231,365) — — (220,949)Other income (expense): Interest expense, net (70,438) — — — (70,438)Loss on derivative financial instruments - commodity derivatives (34,137) — — — (34,137)Gain on restructuring and extinguishment of debt 119,457 — — — 119,457Other income 9 34 — — 43Equity loss — — (16,432) — (16,432)Net loss from consolidated subsidiaries (247,763) — — 247,763 — Total other income (expense) (232,872) 34 (16,432) 247,763 (1,507)Income (loss) before income taxes (222,456) (231,331) (16,432) 247,763 (222,456)Income tax expense 2,802 — — — 2,802Net income (loss) $(225,258) $(231,331) $(16,432) $247,763 $(225,258)118Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO RESOURCES, INC.CONDENSED CONSOLIDATING STATEMENT OF OPERATIONSFor the year ended December 31, 2015(in thousands) Resources GuarantorSubsidiaries Non-GuarantorSubsidiaries Eliminations ConsolidatedRevenues: Oil and natural gas $4 $329,254 $— $— $329,258Purchased natural gas and marketing — 26,442 — — 26,442Total revenues 4 355,696 — — 355,700Costs and expenses: Oil and natural gas production 37 76,496 — — 76,533Gathering and transportation — 99,321 — — 99,321Purchased natural gas — 27,369 — — 27,369Depletion, depreciation and amortization 943 214,483 — — 215,426Impairment of oil and natural gas properties 9,316 1,206,054 — — 1,215,370Accretion of discount on asset retirement obligations 4 2,273 — — 2,277General and administrative (4,313) 63,131 — — 58,818Other operating items 1,646 (1,185) — — 461 Total costs and expenses 7,633 1,687,942 — — 1,695,575Operating loss (7,629) (1,332,246) — — (1,339,875)Other income (expense): Interest expense, net (106,082) — — — (106,082)Gain on derivative financial instruments - commodity derivative 75,869 — — — 75,869Gain on restructuring of debt 193,276 — — — 193,276Other income 87 35 — — 122Equity loss — — (15,691) — (15,691)Net loss from consolidated subsidiaries (1,347,902) — — 1,347,902 — Total other income (expense) (1,184,752) 35 (15,691) 1,347,902 147,494Income (loss) before income taxes (1,192,381) (1,332,211) (15,691) 1,347,902 (1,192,381)Income tax expense — — — — —Net income (loss) $(1,192,381) $(1,332,211) $(15,691) $1,347,902 $(1,192,381)119Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO RESOURCES, INC.CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWSFor the year ended December 31, 2017(in thousands) Resources GuarantorSubsidiaries Non-GuarantorSubsidiaries Eliminations ConsolidatedOperating Activities: Net cash provided by (used in) operating activities $(22,761) $77,172 $— $— $54,411Investing Activities: Additions to oil and natural gas properties, gathering assets andequipment and property acquisitions (1,347) (169,820) — — (171,167)Proceeds from disposition of property and equipment — 350 — — 350Restricted cash — (4,121) — — (4,121)Net changes in advances to joint ventures — (9,161) — — (9,161)Equity investments and other — 1,548 — — 1,548Advances/investments with affiliates (110,001) 110,001 — — —Net cash used in investing activities (111,348) (71,203) — — (182,551)Financing Activities: Borrowings under EXCO Resources Credit Agreement 163,401 — — — 163,401Repayments under EXCO Resources Credit Agreement (265,592) — — — (265,592)Proceeds received from issuance of 1.5 Lien Notes 295,530 — — — 295,530Payments on Exchange Term Loan (11,602) — — — (11,602)Payments of common share dividends (6) — — — (6)Debt financing costs and other (23,062) — — — (23,062)Net cash provided by financing activities 158,669 — — — 158,669Net increase (decrease) in cash 24,560 5,969 — — 30,529Cash at beginning of period 24,610 (15,542) — — 9,068Cash at end of period $49,170 $(9,573) $— $— $39,597120Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO RESOURCES, INC.CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWSFor the year ended December 31, 2016(in thousands) Resources GuarantorSubsidiaries Non-GuarantorSubsidiaries Eliminations ConsolidatedOperating Activities: Net cash provided by (used in) operating activities $572 $(986) $— $— $(414)Investing Activities: Additions to oil and natural gas properties, gathering assets andequipment and property acquisitions (1,521) (78,904) — — (80,425)Proceeds from disposition of property and equipment 10 14,339 — — 14,349Restricted cash — 7,970 — — 7,970Net changes in advances to joint ventures — 3,097 — — 3,097Advances/investments with affiliates (60,991) 60,991 — — —Net cash provided by (used in) investing activities (62,502) 7,493 — — (55,009)Financing Activities: Borrowings under EXCO Resources Credit Agreement 404,897 — — — 404,897Repayments under EXCO Resources Credit Agreement (243,797) — — — (243,797)Repurchases of senior unsecured notes (53,298) — — — (53,298)Payment on Exchange Term Loan (50,695) — — — (50,695)Payments of common share dividends (91) — — — (91)Deferred financing costs and other (4,772) — — — (4,772)Net cash provided by financing activities 52,244 — — — 52,244Net increase (decrease) in cash (9,686) 6,507 — — (3,179)Cash at beginning of period 34,296 (22,049) — — 12,247Cash at end of period $24,610 $(15,542) $— $— $9,068121Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO RESOURCES, INC.CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWSFor the year ended December 31, 2015(in thousands) Resources GuarantorSubsidiaries Non-guarantorsubsidiaries Eliminations ConsolidatedOperating Activities: Net cash provided by operating activities $34,532 $99,495 $— $— $134,027Investing Activities: Additions to oil and natural gas properties, gathering assets andequipment (2,601) (322,597) — — (325,198)Proceeds from disposition of property and equipment 686 6,711 — — 7,397Restricted cash — 4,850 — — 4,850Net changes in advances to joint ventures — 10,663 — — 10,663Equity investments and other — 1,455 — — 1,455Advances/investments with affiliates (217,906) 217,906 — — —Net cash used in investing activities (219,821) (81,012) — — (300,833)Financing Activities: Borrowings under EXCO Resources Credit Agreement 165,000 — — — 165,000Repayments under EXCO Resources Credit Agreement (300,000) — — — (300,000)Proceeds received from issuance of Fairfax Term Loan 300,000 — — — 300,000Repurchases of senior unsecured notes (12,008) — — — (12,008)Payment on Exchange Term Loan (8,827) — — — (8,827)Proceeds from issuance of common shares, net 9,693 — — — 9,693Payments of common share dividends (164) — — — (164)Deferred financing costs and other (20,946) — — — (20,946)Net cash provided by financing activities 132,748 — — — 132,748Net increase (decrease) in cash (52,541) 18,483 — — (34,058)Cash at beginning of period 86,837 (40,532) — — 46,305Cash at end of period $34,296 $(22,049) $— $— $12,247122Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.15.Quarterly financial data (unaudited)The following are summarized quarterly financial data for the years ended December 31, 2017 and 2016: Quarter(in thousands, except per share amounts) 1st 2nd 3rd 4th2017 Total revenues $76,529 $71,015 $66,736 $69,366Operating income (loss) (1) 13,587 15,216 (5,142) (64,217)Net income (loss) (2) $8,193 $120,750 $(18,824) $(85,757)Basic earnings (loss) per share: Net income (loss) $0.44 $6.13 $(0.81) $(3.68)Weighted average shares 18,726 19,702 23,319 23,333Diluted earnings (loss) per share: Net income (loss) $0.44 $6.07 $(0.81) $(3.68)Weighted average shares 18,749 19,886 23,319 23,333 2016 Total revenues $56,090 $58,791 $77,186 $78,934Operating income (loss) (3) (164,698) (72,997) 4,142 12,604Net income (loss) (4) $(130,148) $(111,347) $50,936 $(34,699)Basic earnings (loss) per share: Net income (loss) $(7.01) $(5.99) $2.73 $(1.86)Weighted average shares 18,568 18,597 18,670 18,686Diluted earnings (loss) per share: Net income (loss) $(7.01) $(5.99) $2.72 $(1.86)Weighted average shares 18,568 18,597 18,749 18,686(1)Operating loss for the fourth quarter of 2017 includes the acceleration of the remaining charges under a firm transportation agreement of $56.4 million. See "Note 8.Commitments and contingencies" for further discussion.(2)Net income (loss) includes gains on the revaluation of the 2017 Warrants of $6.0 million, $122.3 million, $18.3 million and $12.6 million during the first, second, third,and fourth quarters of 2017, respectively, primarily due to a decrease in EXCO's share price. See "Note 4. Derivative financial instruments" for further discussion.(3)Operating loss for the first and second quarter of 2016 includes $134.6 million and $26.2 million, respectively, of impairments of oil and natural gas properties. See "Note2. Summary of significant accounting policies" for further discussion.(4)Net income (loss) for the first, second and third quarter of 2016 includes $45.1 million, $16.8 million and $57.4 million net gains on extinguishment of debt. See "Note 5.Debt" for further discussion.123Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.16.Supplemental information relating to oil and natural gas producing activities (unaudited) The following supplemental information relating to our oil and natural gas producing activities for the years ended December 31, 2017, 2016 and2015 is presented in accordance with ASC 932, Extractive Activities, Oil and Gas.Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities:(in thousands, except per unit amounts) Amount2017: Proved property acquisition costs $18,940Unproved property acquisition costs 5,228Total property acquisition costs 24,168Development 128,323Exploration costs (1) 19,538Lease acquisitions and other 5,654Capitalized asset retirement costs 12Depletion per Boe $3.45Depletion per Mcfe $0.572016: Proved property acquisition costs $638Unproved property acquisition costs 393Total property acquisition costs 1,031Development 62,328Exploration costs —Lease acquisitions and other 760Capitalized asset retirement costs —Depletion per Boe $4.28Depletion per Mcfe $0.712015: Proved property acquisition costs $7,608Unproved property acquisition costs —Total property acquisition costs 7,608Development 215,239Exploration costs (1) 13,306Lease acquisitions and other 13,017Capitalized asset retirement costs 881Depletion per Boe $10.32Depletion per Mcfe $1.72(1)Exploration costs in 2017 related to the wells drilled in the Bossier shale in North Louisiana. Exploration costs in 2015 related to the wells drilled in the Buda formation inSouth Texas.We retain independent engineering firms to prepare or audit annual year-end estimates of our future net recoverable oil and natural gas reserves. Theestimated proved net recoverable reserves we show below include only those quantities that we expect to be commercially recoverable at prices and costs ineffect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reservesrepresent only those reserves that we may recover through existing wells. Proved Undeveloped Reserves include those reserves that we may recover from newwells on undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations.All of our reserves are located onshore in the continental United States of America.124Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of our oil and natural gasproperties. Estimates of fair value should also consider unproved reserves, anticipated future oil and natural gas prices, interest rates, changes in developmentand production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective andimprecise. Oil(Mbbls) NaturalGas(Mmcf) Mmcfe (8)December 31, 2014 17,6871,157,6741,263,796Purchase of reserves in place (1) 4591222,876Discoveries and extensions (2) 7,602152,473198,085Revisions of previous estimates: Changes in price (2,821)(598,865)(615,791)Other factors (3) (145)184,641183,771Sales of reserves in place (1)(1,445)(1,451)Production (2,342)(109,926)(123,978)December 31, 2015 20,439784,674907,308Purchase of reserves in place —552552Discoveries and extensions (4) —16,38116,381Revisions of previous estimates: Changes in price (2,061)(55,748)(68,114)Other factors (5) (5,165)(208,714)(239,704)Sales of reserves in place (1,276)(27,597)(35,253)Production (1,769)(93,829)(104,443)December 31, 2016 10,168415,719476,727Purchase of reserves in place (6) — 50,456 50,456Discoveries and extensions 13 21,880 21,958Revisions of previous estimates: Changes in price 679 30,200 34,274Other factors (7) (290) 72,332 70,593Sales of reserves in place ———Production (1,158) (80,136) (87,084)December 31, 2017 9,412 510,451 566,924Estimated Quantities of Proved Developed and Proved Undeveloped Reserves Oil(Mbbls) NaturalGas(Mmcf) MmcfeProved developed: December 31, 2017 9,412 510,451 566,924December 31, 2016 10,168 415,719476,727December 31, 2015 12,056 364,932437,268Proved undeveloped: December 31, 2017 — — —December 31, 2016 — ——December 31, 2015 8,383 419,742470,040(1)Purchases of reserves in place include the acquisition of certain proved developed producing properties in the Eagle Ford shale in connection with the ParticipationAgreement.(2)New discoveries and extensions in 2015 include 84.9 Bcfe and 41.0 Bcfe in the Haynesville shale and Bossier shale, respectively, related to our development ofproperties within the Shelby area of East Texas. Additionally, extensions and discoveries in 2015 included 24.7 Bcfe in the in the Haynesville shale related to thedevelopment of the Holly area in North Louisiana and 47.5 Bcfe in the Eagle Ford shale.125Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(3)Total revisions due to Other factors include upward revisions of approximately 152.2 Bcfe in the North Louisiana Holly area and are primarily due to modifications in thewell design to incorporate more proppant and longer laterals. The upward revisions also included 36.7 Bcfe from our East Texas region primarily due to strong results inboth the Haynesville and Bossier shales based on our enhanced completion methods. The upward revisions also reflect a reduction in capital costs and operatingexpenses.(4)New discoveries and extensions in 2016 include 14.9 Bcfe in the Haynesville and Bossier shales related to our development of properties within the Shelby area of EastTexas.(5)Total revisions due to Other factors include downward revisions of approximately 427.6 Bcfe as a result of the reclassification of our Proved Undeveloped Reserves tounproved during the first quarter of 2016 due to the uncertainty regarding the financing required to develop these reserves that existed on March 31, 2016. These reservesremained reclassified in unproved due to our inability to meet the Reasonable Certainty criteria for recording Proved Undeveloped Reserves, as prescribed under the SECrequirements, as the uncertainty regarding our ability of capital required to develop these reserves still existed at December 31, 2016. This was offset by approximately99.0 Bcfe of upward revisions in the Marcellus shale primarily due to the narrowing of regional price differentials, reductions in our operating expenses, and improvedwell performance due to shallower declines than previously forecasted. The upward revision also reflects a reduction in operating expenses in other areas, primarily NorthLouisiana and South Texas, which increased our reserves by 51.4 Bcfe and 23.9 Bcfe, respectively. Lower operating costs were primarily the result of various costreduction efforts, including significant reductions in labor costs, chemical treatment costs and saltwater disposal costs. Reductions in our operating costs extend theeconomic life of certain properties and resulted in upward revisions to our reserve quantities. In addition, the upward revisions in North Louisiana reflect improvedperformance of certain Haynesville shale wells that the Company turned-to-sales during 2016. These wells featured enhanced completion methods including moreproppant per lateral foot.(6)Purchases of reserves in place primarily related to the acquisition of incremental interests in certain oil and natural gas properties that we operate and undeveloped acreagein the North Louisiana region.(7)Total revisions due to Other factors primarily include the reclassification of wells to Proved Reserves during 2017 that were previously reclassified to unproved reservesin prior years due to capital constraints. These reclassifications primarily related to conversions of wells to Proved Developed Reserves as a result of our developmentactivities in the North Louisiana region.(8)The above reserves do not include our equity interest in OPCO, which was not significant in any period presented.126Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Standardized measure of discounted future net cash flowsWe have summarized the Standardized Measure related to our proved oil and natural gas reserves. We have based the following summary on avaluation of Proved Reserves using discounted cash flows based on prices as prescribed by the SEC, costs and economic conditions and a 10% discount rate.The additions to Proved Reserves from the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year;additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Furthermore, the ability todemonstrate the financing available to fund a development program with Reasonable Certainty could have a significant impact on our Proved UndevelopedReserves. Accordingly, the information presented below should not be viewed as an estimate of the fair value of our oil and natural gas properties, nor shouldit be indicative of any trends.(in thousands) AmountYear ended December 31, 2017: Future cash inflows $1,690,056Future production costs 863,847Future development costs (1) 51,925Future income taxes —Future net cash flows 774,284Discount of future net cash flows at 10% per annum 291,537Standardized measure of discounted future net cash flows $482,747Year ended December 31, 2016: Future cash inflows $1,216,855Future production costs 705,873Future development costs (1) 39,956Future income taxes —Future net cash flows 471,026Discount of future net cash flows at 10% per annum 160,095Standardized measure of discounted future net cash flows $310,931Year ended December 31, 2015: Future cash inflows $2,684,362Future production costs 1,280,795Future development costs 641,768Future income taxes —Future net cash flows 761,799Discount of future net cash flows at 10% per annum 359,666Standardized measure of discounted future net cash flows $402,133(1)All of our Proved Undeveloped Reserves were reclassified to unproved during 2016 due to the uncertainty regarding the financing required to develop these reserves. These reserves remained classified as unproved due to our inability to meet the Reasonable Certainty criteria for recording Proved Undeveloped Reserves, as prescribedunder the SEC requirements, as the uncertainty regarding our availability of capital required to develop these reserves still existed at December 31, 2017 and 2016. Assuch, future development costs at December 31, 2017 and 2016 consist primarily of estimated future plugging and abandonment costs.During recent years, prices paid for oil and natural gas have fluctuated significantly. The reference prices at December 31, 2017, 2016 and 2015 usedin the above table, were $51.34, $42.75 and $50.28 per Bbl of oil, respectively, and $2.98, $2.48 and $2.59 per Mmbtu of natural gas, respectively. Each ofthe reference prices for oil and natural gas were adjusted for quality factors and regional differentials. These prices reflect the SEC rules requiring the use ofsimple average of the first day of the month price for the previous 12 month period for natural gas at Henry Hub and West Texas Intermediate crude oil atCushing, Oklahoma.127Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.The following are the principal sources of change in the Standardized Measure: (in thousands) AmountYear ended December 31, 2017: Sales and transfers of oil and natural gas produced $(99,260)Net changes in prices and production costs 91,998Extensions and discoveries, net of future development and production costs 25,459Development costs during the period to the extent previously estimated 1,913Changes in estimated future development costs (4,758)Revisions of previous quantity estimates 88,825Sales of reserves in place —Purchase of reserves in place 40,991Accretion of discount 31,093Changes in timing and other (4,444)Net change in income taxes —Net change $171,817Year ended December 31, 2016: Sales and transfers of oil and natural gas produced $(92,200)Net changes in prices and production costs (260,335)Extensions and discoveries, net of future development and production costs 16,258Development costs during the period to the extent previously estimated 46,499Changes in estimated future development costs 384,644Revisions of previous quantity estimates (180,367)Sales of reserves in place (11,814)Purchase of reserves in place 347Accretion of discount 40,213Changes in timing and other (34,447)Net change in income taxes —Net change $(91,202)Year ended December 31, 2015: Sales and transfers of oil and natural gas produced $(153,404)Net changes in prices and production costs (1,438,023)Extensions and discoveries, net of future development and production costs 99,818Development costs during the period to the extent previously estimated 109,895Changes in estimated future development costs 407,780Revisions of previous quantity estimates (232,325)Sales of reserves in place (1,632)Purchase of reserves in place 6,892Accretion of discount 126,533Changes in timing and other (65,988)Net change in income taxes —Net change $(1,140,454)128Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Costs not subject to amortizationThe following table summarizes the categories of costs comprising the amount of unproved properties not subject to amortization by the year in whichsuch costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. Asignificant portion of our acreage is held-by-production, which allows us to develop these properties within an optimum time frame.(in thousands) Total 2017 2016 2015 2014 andpriorProperty acquisition costs $71,244$10,890$899$11,121$48,334Exploration and development 10,82010,820———Capitalized interest 36,5886,4405,2138,46416,471Total $118,652$28,150$6,112$19,585$64,80517.Subsequent eventsChapter 11 CasesOn January 15, 2018, the Company and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in theUnited States Bankruptcy Court for the Southern District of Texas. The Chapter 11 Cases are being jointly administered under the caption In Re EXCOResources, Inc., Case No. 18-30155 (MI). The Court has granted all of the first day motions filed by the Debtors that were designed primarily to minimize theimpact of the Chapter 11 proceedings on our operations, customers and employees. We will continue to operate our businesses as “debtors in possession”under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Court. We expect to continueour operations without interruption during the pendency of the Chapter 11 proceedings.Impact on indebtednessAs of January 15, 2018, we had approximately $1.4 billion in principal amount of indebtedness, including approximately: (i) $126.4million outstanding under the EXCO Resources Credit Agreement, (ii) $317.0 million in outstanding under the 1.5 Lien Notes, (iii) $708.9million outstanding under the 1.75 Lien Term Loans, (iv) $17.2 million outstanding under the Second Lien Term Loans, (v) $131.6 million outstandingunder the 2018 Notes and (vi) $70.2 million outstanding under the 2022 Notes. The commencement of the Chapter 11 Cases described above constituted anevent of default that accelerated our obligations under the following debt instruments:•EXCO Resources Credit Agreement;•1.5 Lien Notes;•1.75 Lien Term Loans;•2018 Notes; and•2022 Notes.These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall beimmediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of thecommencement of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments are subject to the applicable provisions ofthe Bankruptcy Code. As a result of the bankruptcy proceedings, the Court may limit post-petition interest on debt that may be under secured or unsecured.On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes.DIP Credit AgreementOn January 22, 2018, we closed the DIP Credit Agreement with lenders including affiliates of Fairfax, Bluescape and JPMorgan Chase Bank, N.A.("DIP Lenders"). Hamblin Watsa Investment Counsel Ltd. is the administrative agent (“DIP Agent”) for the DIP Credit Agreement. The DIP Credit Agreementincludes the Revolver A Facility in an aggregate principal amount of $125.0 million and the Revolver B Facility in an aggregate principal amount of $125.0million.129Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.All amounts outstanding under the DIP Facilities bear interest at an adjusted LIBOR plus 4.00% per annum. During the continuance of an event ofdefault, the outstanding amounts under the DIP Facilities bear interest at an additional 2.00% per annum above the interest rate otherwise applicable.The DIP Facilities will mature on the earliest of (a) 12 months from the initial borrowings on January 22, 2018, (b) the effective date of a plan ofreorganization in the Chapter 11 Cases, or (c) the date of termination of all revolving commitments and/or the acceleration of the obligations under the DIPFacilities following an event of default. We have the option, subject to certain conditions, to extend the maturity of the DIP Facilities to the date that is 18months from the initial borrowing date. Borrowings under the DIP Credit Agreement are subject to a borrowing base based on the value of our oil and gasreserves. Beginning on January 1, 2019, the borrowing base will be subject to adjustment semi-annually, on April 1 and October 1 of each year. The initialborrowing base under the DIP Facilities is $250.0 million. The DIP Lenders have considerable discretion in setting our borrowing base as part of theredetermination process. However, we may elect to redetermine the borrowing base to an amount equal to two-thirds of the net present value, discounted atnine percent, of our Proved Developed Reserves.The proceeds of the DIP Facilities may be used in accordance with the DIP Credit Agreement to (i) repay obligations outstanding under the EXCOResources Credit Agreement, (ii) pay for operating expenses incurred during the Chapter 11 Cases subject to a budget provided to the DIP Lenders under theDIP Credit Agreement, (iii) pay for certain transaction costs, fees and expenses, and (iv) pay for certain other costs and expenses of administering the Chapter11 Cases. We used approximately $104.0 million of the proceeds provided through the DIP Facilities to refinance all obligations outstanding under theEXCO Resources Credit Agreement (the “ERCA Refinancing”). Under the DIP Credit Agreement, approximately $24.0 million of outstanding letters of creditwere deemed issued under the Revolver A Facility, and approximately $21.6 million of loans outstanding under the EXCO Resources Agreement weredeemed exchanged for loans under the Revolver B Facility. On January 18, 2018, the Court entered an interim order (the “DIP Interim Order”) that authorizedus to enter into the DIP Facilities. Under the Interim Order, the ERCA Refinancing was subject to a challenge and review period that expired on the date ofthe Court hearing on the final order (the “DIP Challenge Period”). On February 22, 2018, the Court entered into a final order authorizing entry into the DIPCredit Agreement on a final basis. The entry into the final order resulted in the expiration of the DIP Challenge Period and the termination of the EXCOResources Credit Agreement. As of February 28, 2018, we had $156.4 million in outstanding indebtedness under the DIP Facilities, excluding letters ofcredit. Our available borrowing capacity under the DIP Facilities was $69.6 million as of February 28, 2018.The DIP Lenders and the DIP Agent, subject to the Carve-Out (as defined below) and the terms of the Interim Order, at all times: (i) are entitled to jointand several super-priority administrative expense claim status in the Chapter 11 cases; (ii) have a first priority lien on substantially all of our assets; (iii) havea junior lien on any of our assets subject to a valid, perfected and non-avoidable lien as of the Petition Date, other than such liens securing the obligationsunder the EXCO Resources Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans and Second Lien Term Loans, and (iv) have a first priority pledge of100% of the stock and other equity interests in each of our direct and indirect subsidiaries. Our obligations to the DIP Lenders and the liens and super-priorityclaims are subject in each case to a carve out (the “Carve-Out”) that accounts for certain administrative, court and legal fees payable in connection with theChapter 11 Cases.The DIP Credit Agreement contains certain financial covenants, including, but not limited to:•our cash (as defined in the DIP Credit Agreement) plus unused commitments under the DIP Credit Agreement cannot be less than of $20.0 million;and•aggregate disbursements cannot exceed 120% of the aggregate disbursements (excluding professional fees incurred in the Chapter 11 Cases) setforth in the 13-week forecasts provided to the administrative agent of the DIP Credit Agreement. The testing period is based on the immediatelypreceding four-week period and is measured every two weeks. The 13-week forecast is provided to the DIP Agent on a monthly basis and shall beconsistent in all material respects with the applicable period covered by the 2018 budget that was previously delivered to the administrative agentof the DIP Credit Agreement.The DIP Facilities contain events of default, including: (i) conversion of the Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code and(ii) appointment of a trustee, examiner or receiver in the Chapter 11 Cases. The DIP Facilities contained an event of default if we failed to pursue a Courthearing no later than July 1, 2018 to consider the sale of all or substantially all of our assets. This requirement to pursue the court hearing to consider the saleof assets may have been waived by Fairfax, and the DIP Lenders and the Company were required negotiate in good faith the terms of a plan of reorganizationto equitize certain indebtedness as an alternative to the sale process. On February 22, 2018, the final order entered by the Court deemed the requirement topursue a Court hearing to consider the sale of all or substantially all of our assets to be no longer in force and effect.130Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.The foregoing description does not purport to be a complete description of the DIP Credit Agreement, a copy of which is filed as an exhibit to theCurrent Report on Form 8-K, dated January 25, 2018.Automatic stay Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actionsagainst the Company and the Filing Subsidiaries as well as efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. As a result, for example, most creditor actions to obtain possession of property from us or any of the Filing Subsidiaries, or to create, perfect orenforce any lien against our property or any of the Filing Subsidiaries, or to collect on or otherwise exercise rights or remedies with respect to a pre-petitionclaim are stayed.Executory contractsSubject to certain exceptions, under the Bankruptcy Code, the Company and the Filing Subsidiaries may assume, assign, or reject certain executorycontracts and unexpired leases subject to the approval of the Court and fulfillment of certain other conditions. The rejection of an executory contract orunexpired lease is generally treated as a breach as of the petition date of such executory contract or unexpired lease and, subject to certain exceptions,relieves the Company and the Filing Subsidiaries of performing their future obligations under such executory contract or unexpired lease but may give rise toa general unsecured claim against us or the applicable Filing Subsidiaries for damages caused by such rejection. The assumption of an executory contract orunexpired lease generally requires the Company and the Filing Subsidiaries to cure existing monetary or other defaults under such executory contract orunexpired lease and provide adequate assurance of future performance. Any description of the treatment of an executory contract or unexpired lease with theCompany or any of the Filing Subsidiaries, including any description of the obligations under any such executory contract or unexpired lease, is qualified byand subject to any rights we have with respect to executory contracts and unexpired leases under the Bankruptcy Code.On January 18, 2018, the Company and the Filings Subsidiaries filed motions to reject certain executory contracts as permitted under the BankruptcyCode. The contracts include the following:•Firm transportation agreements with Acadian, which required us to transport 325,000 Mmbtu per day on the Acadian Gas Pipeline System or payreservation charges through October, 31, 2025;•Natural gas sales agreements with Enterprise, which required us to sell 75,000 Mmbtu per day of natural gas to Enterprise or incur certain coststhrough October 31, 2025;•Firm transportation agreements with Regency, which required us to either transport 237,500 Mmbtu per day of natural gas or pay reservation chargesthrough January 31, 2020;•Marketing agreement with Chesapeake, which required us to allow Chesapeake to purchase natural gas for certain wells in North Louisiana through2021; and•Natural gas sales agreements with Shell, which required us to sell 100,000 Mmbtu per day of natural gas to Shell or incur certain costs throughNovember 30, 2020.On March 7, 2018, the Court approved the rejection of the aforementioned executory contracts with Regency, Chesapeake and Shell. The hearing toconsider the motion to reject the Enterprise and Acadian contracts is scheduled for March 29, 2018. On March 1, 2018, the Company and the FilingSubsidiaries filed a motion to reject an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and NorthLouisiana to certain gathering systems through November 30, 2018. The hearing to consider this motion is scheduled for March 29, 2018. See furtherdiscussion of the future minimum obligations under these contracts as of December 31, 2017 in "Note 8. Commitments and contingencies".Chapter 11 filing impact on creditors and shareholdersUnder the priority requirements established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities to creditors and post-petition liabilities must be satisfied in full before the holders of our existing common shares are entitled to receive any distribution or retain any propertyunder a plan of reorganization. The ultimate recovery to creditors, if any, will not be determined until confirmation and implementation of a plan ofreorganization. The outcome of the Chapter 11 Cases remains uncertain at this time and, as a result, we cannot accurately estimate the amounts or value ofdistributions that creditors may receive. We believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11Cases, and the holders of our existing common shares will be entitled to a limited recovery, if any.131Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Restrictions on trading of our equity securities to protect our use of net operating losses The Court has entered a final order pursuant to Sections 362(a)(3) and 541 of the Bankruptcy Code enabling the Company and the Filing Subsidiariesto avoid limitations on the use of our income tax net operating loss carryforwards and certain other tax attributes by imposing certain notice procedures andtransfer restrictions on the trading of our equity securities. In general, the order applies to any person that, directly or indirectly, beneficially owns (or wouldbeneficially own as a result of a proposed transfer) at least 4.5% of our outstanding common stock (a “Substantial Stockholder”), and requires that eachSubstantial Stockholder file with the Court and serve us with notice of such status. Under the order, prior to any proposed acquisition or disposition of equitysecurities that would result in an increase or decrease in the amount of our equity securities owned by a Substantial Stockholder, or that would result in aperson or entity becoming a Substantial Stockholder, such person or entity is required to file with the Court and notify us of such acquisition or disposition.We have the right to seek an injunction from the Court to prevent certain acquisitions or sales of our common shares if the acquisition or sale would pose amaterial risk of adversely affecting our ability to utilize such tax attributes.Risks associated with Chapter 11 proceedingsFor the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks anduncertainties associated with the Chapter 11 proceedings as described in "Item 1A. Risk Factors”. As a result of these risks and uncertainties, our assets,liabilities, shareholders' equity, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and thedescription of our operations, properties and capital plans included in this Annual Report may not accurately reflect our operations, properties and capitalplans following the Chapter 11 process.Appalachia JV SettlementOn January 26, 2018, we filed a motion to authorize the entry into a settlement agreement with a subsidiary of Shell to resolve arbitration regardingour right to participate in an area of mutual interest in the Appalachia region. The final order related to this settlement was approved on February 22, 2018and we closed the settlement agreement on February 27, 2018. Under the terms of the settlement:•Shell transferred its interests to EXCO in each of BG Production Company (PA), LLC, BG Production Company (WV), LLC, OPCO, and theAppalachia Midstream JV;•Shell and EXCO terminated and considered to be fulfilled obligations and liabilities under certain specified agreements related to the AppalachiaJV;•EXCO reconveyed its interests in certain leases, representing an interest in 364 net acres, that EXCO had previously acquired from Shell within thearea of mutual interest, in exchange for consideration of $0.7 million;•EXCO and Shell mutually released all existing, future, known, and unknown claims for all existing, future, known, and unknown damages andremedies that each party may have against one another arising out of or relating to the joint development agreement, the area of mutual interest,the arbitration, the state court action, and all joint venture dealings among the parties and certain of their affiliates in the Appalachia region,except as expressly provided in the settlement; and•EXCO caused the arbitration and the state court action to be dismissed with prejudice.The settlement increased our acreage in the Appalachia region by approximately 177,700 net acres, and the production from the additional interests inproducing wells acquired was 26 net Mmcfe per day during December 2017. In addition, EXCO owns 100% of OPCO and the Appalachia Midstream JVsubsequent to the settlement.Item 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureNone.Item 9A. Controls and ProceduresDisclosure controls and procedures. Pursuant to Rule 13a-15(b) under the Exchange Act, EXCO's management has evaluated, under the supervisionand with the participation of our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosurecontrols and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act), as of the end of the period covered by this report. Based on thisevaluation, our principal executive officer and principal financial officer have concluded that EXCO's disclosure controls and procedures were effective132Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.as of December 31, 2017 to ensure that information that is required to be disclosed by EXCO in the reports it files or submits under the Exchange Act is(i) recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms and (ii) accumulated and communicated toEXCO's management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding requireddisclosure.Management's report on internal control over financial reporting. EXCO's management is responsible for establishing and maintaining adequateinternal control over financial reporting (as defined in Rule 13a-15(f) or 15d-15(f) of the Exchange Act). Management assessed the effectiveness of ourinternal control over financial reporting as of December 31, 2017, using criteria established in Internal Control-Integrated Framework (2013) issued by theCommittee of Sponsoring Organizations of the Treadway Commission (COSO). Even an effective internal control system, no matter how well designed, hasinherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonableassurance with respect to reliable financial reporting. Furthermore, the effectiveness of an internal control system in future periods can change withconditions. Management's annual report of internal control over financial reporting and the audit report on our internal control over financial reporting of ourindependent registered public accounting firm, KPMG LLP, are included in Item 8 of this Annual Report on Form 10-K and are incorporated by referenceherein.Changes in internal control over financial reporting. There were no changes in EXCO's internal control over financial reporting that occurred duringthe quarter ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, EXCO's internal control over financialreporting.Item 9B. Other InformationNone.133Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.PART III Item 10. Directors, Executive Officers and Corporate GovernanceThe information required in response to this Item 10 will be provided in an amendment on Form 10-K/A and will be incorporated by reference therein.Item 11. Executive CompensationThe information required in response to this Item 11 will be provided in an amendment on Form 10-K/A and will be incorporated by reference therein.Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder MattersThe information required in response to this Item 12 will be provided in an amendment on Form 10-K/A and will be incorporated by reference therein.Item 13. Certain Relationships and Related Transactions and Director IndependenceThe information required in response to this Item 13 will be provided in an amendment on Form 10-K/A and will be incorporated by reference therein.Item 14. Principal Accountant Fees and ServicesThe information required in response to this Item 14 will be provided in an amendment on Form 10-K/A and we be incorporated by reference therein.PART IVItem 15. Exhibits and Financial Statement Schedules(a)(1) See Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.(a)(2) None.(a)(3) See "Index to Exhibits" for a description of our exhibits.(b) See "Index to Exhibits" for a description of our exhibits.(c) None.134Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on itsbehalf by the undersigned thereunto duly authorized. Date:March 15, 2018 EXCO RESOURCES, INC. (Registrant) /s/ Harold L. Hickey Harold L. Hickey Chief Executive Officer and President (Principal Executive Officer) 135Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrantand in the capacities and on the dates indicated. Date:March 15, 2018 /s/ Harold L. Hickey Harold L. Hickey Chief Executive Officer and President (Principal Executive Officer) /s/ Tyler S. Farquharson Tyler S. Farquharson Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) /s/ Brian N. Gaebe Brian N. Gaebe Chief Accounting Officer and Corporate Controller (Principal Accounting Officer) /s/ Anthony R. Horton Anthony R. Horton Director /s/ Randall E. King Randall E. King Director /s/ Robert L. Stillwell Robert L. Stillwell Director136Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.INDEX TO EXHIBITSExhibit NumberDescription of Exhibits 2.1#Purchase and Sale Agreement, dated as of April 7, 2017, by and among EXCO Operating Company, LP, EXCO Land Company LLC andVOG Palo Verde LP, filed on August 2, 2017 as an Exhibit to EXCO’s Registration Statement on Form S-3 (File No. 333-219641) andincorporated by reference herein. 2.2#First Amendment to Purchase and Sale Agreement, dated as of May 31, 2017, by and among EXCO Operating Company, LP, EXCO LandCompany LLC and VOG Palo Verde LP, filed on August 2, 2017 as an Exhibit to EXCO’s Registration Statement on Form S-3 (File No.333-219641) and incorporated by reference herein. 2.3#Second Amendment to Purchase and Sale Agreement, dated as of June 20, 2017, by and among EXCO Operating Company, LP, EXCO LandCompany LLC and VOG Palo Verde LP, filed on August 2, 2017 as an Exhibit to EXCO’s Registration Statement on Form S-3 (File No.333-219641) and incorporated by reference herein. 2.4#Agreement to Terminate Purchase and Sale Agreement, dated as of August 14, 2017, by and between EXCO Operating Company, LP, EXCOLand Company, LLC and VOG Palo Verde LP, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter EndedSeptember 30, 2017 filed on November 7, 2017 and incorporated by reference herein. 3.1Amended and Restated Certificate of Formation of EXCO Resources, Inc., as amended through June 2, 2017, filed on August 2, 2017 as anExhibit to EXCO’s Registration Statement on Form S-3 (File No. 333-219641) and incorporated by reference herein. 3.2Third Amended and Restated Bylaws of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September8, 2015 and filed on September 9, 2015 and incorporated by reference herein. 4.1Indenture, dated September 15, 2010, by and between EXCO Resources, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibitto EXCO’s Current Report on Form 8-K (File No. 001-32743), dated September 10, 2010 and filed on September 15, 2010 and incorporatedby reference herein. 4.2First Supplemental Indenture, dated September 15, 2010, by and among EXCO Resources, Inc., certain of its subsidiaries and WilmingtonTrust Company, as trustee, including the form of 7.500% Senior Notes due 2018, filed as an Exhibit to EXCO’s Current Report on Form 8-K(File No. 001-32743), dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein. 4.3Second Supplemental Indenture, dated as of February 12, 2013, by and among EXCO Resources, Inc., EXCO/HGI JV Assets, LLC, EXCOHolding MLP, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO's Current Report on Form 8-K (File No. 001-32743), dated February 12, 2013 and filed on February 19, 2013 and incorporated by reference herein. 4.4Third Supplemental Indenture, dated April 16, 2014, by and among EXCO Resources, Inc., certain of its subsidiaries and Wilmington TrustCompany, as trustee, including the form of 8.500% Senior Notes due 2022, filed as an Exhibit to EXCO’s Current Report on Form 8-K,dated April 11, 2014 and filed on April 16, 2014 and incorporated by reference herein. 4.5Fourth Supplemental Indenture, dated May 12, 2014, by and among EXCO Resources, Inc., EXCO Land Company, LLC and WilmingtonTrust Company, as trustee, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2014 and filed onJuly 30, 2014 and incorporated by reference herein. 4.6Fifth Supplemental Indenture, dated November 24, 2015, by and among EXCO Resources, Inc., certain of its subsidiaries, and WilmingtonTrust Company, as trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 24, 2015 and filed on November 25,2015 and incorporated by reference herein. 4.7Sixth Supplemental Indenture, dated August 9, 2016, by and among EXCO Resources, Inc., certain of its subsidiaries, and Wilmington TrustCompany, as trustee, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated August 9, 2016 and filed on August 10, 2016 andincorporated by reference herein. 137Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.4.8Instrument of Resignation, Appointment and Acceptance, dated as of December 15, 2017, by and among EXCO Resources, Inc.,Wilmington Trust, National Association and Wilmington Savings Fund Society, FSB filed as an Exhibit to EXCO’s Current Report on Form8-K, dated December 15, 2017 filed December 21, 2017 and incorporated by reference herein. 4.9Instrument of Appointment and Acceptance, dated as of January 23, 2018, by and among EXCO Resources, Inc., Phoenix InvestmentAdvisers LLC and GLAS Trust Company LLC filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 19, 2018 filedJanuary 25, 2018 and incorporated by reference herein. 4.10Indenture, dated as of March 15, 2017, by and among EXCO Resources, Inc., as issuer, certain of its subsidiaries, as guarantors, andWilmington Trust, National Association, as trustee and collateral trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, datedMarch 15, 2017 and filed on March 15, 2017 and incorporated by reference herein. 4.11First Supplemental Indenture, dated as of April 4, 2017, by and among EXCO Resources, Inc., as issuer, certain of its subsidiaries, asguarantors, and Wilmington Trust, National Association, as trustee and collateral trustee, filed on May 10, 2017 as an Exhibit to EXCO'sQuarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 and incorporated by reference herein. 4.12Second Supplemental Indenture, dated as of April 14, 2017, by and among EXCO Resources, Inc., as issuer, certain of its subsidiaries, asguarantors, and Wilmington Trust, National Association, as trustee and collateral trustee, filed on May 10, 2017 as an Exhibit to EXCO'sQuarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 and incorporated by reference herein. 4.13Specimen Stock Certificate for EXCO’s common stock, filed as an Exhibit to EXCO’s Registration Statement on Form S-3, filed onDecember 17, 2013 and incorporated by reference herein. 4.14First Amended and Restated Registration Rights Agreement dated as of December 30, 2005, by and among EXCO Holdings Inc. and theInitial Holders (as defined therein), filed as an Exhibit to EXCO’s Amendment No. 1 to its Registration Statement on Form S-l (File No. 333-129935), filed on January 6, 2006 and incorporated by reference herein. 4.15Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to the7.0% Cumulative Convertible Perpetual Preferred Stock and the Hybrid Preferred Stock, filed as an Exhibit to EXCO’s Current Report onForm 8-K (File No. 001-32743) dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein. 4.16Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to theHybrid Preferred Stock, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743) dated March 28, 2007 and filed onApril 2, 2007 and incorporated by reference herein. 4.17Joinder Agreement to Registration Rights Agreement, dated January 17, 2014, by and among EXCO Resources, Inc. and WLR IV Exco AIVOne, L.P., WLR IV Exco AIV Two, L.P., WLR IV Exco AIV Three, L.P., WLR IV Exco AIV Four, L.P., WLR IV Exco AIV Five, L.P., WLR IVExco AIV Six, L.P., WLR Select Co-Investment XCO AIV, L.P., WLR/GS Master Co-Investment XCO AIV, L.P. and WLR IV Parallel ESC,L.P, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 21, 2014 and incorporated byreference herein. 4.18Joinder Agreement to Registration Rights Agreement, dated January 17, 2014, by and among EXCO Resources, Inc. and Advent Syndicate780, Clearwater Insurance Company, Northbridge General Insurance Company, Odyssey Reinsurance Company, Clearwater SelectInsurance Company, Riverstone Insurance Limited, Zenith Insurance Company and Fairfax Master Trust Fund, filed as an Exhibit toEXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 21, 2014 and incorporated by reference herein. 4.19Registration Rights Agreement, dated as of April 21, 2015, by and between EXCO Resources, Inc. and Energy Strategic Advisory ServicesLLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 21, 2015 and filed on April 27, 2015 and incorporated byreference herein. 4.20Registration Rights Agreement, dated as of March 15, 2017, by and among EXCO Resources, Inc. and the investors specified on thesignatures thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 andincorporated by reference herein. 138Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.4.21Form of Financing Warrant, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017and incorporated by reference herein. 4.22Form of Commitment Fee Warrant, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March15, 2017 and incorporated by reference herein. 4.23Form of Amendment Fee Warrant, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15,2017 and incorporated by reference herein. 10.1Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743),dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.* 10.2Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed asan Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 andincorporated by reference herein.* 10.3Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filedas an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 andincorporated by reference herein.* 10.4Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed asan Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated August 4, 2011 and filed on August 10, 2011 andincorporated by reference herein.* 10.5Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed asan Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2013 filed on August 7, 2013 and incorporated byreference herein.* 10.6Form of Restricted Stock Award Agreement for Named Executive Officers for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2015 filed on July 27,2015 and incorporated by reference herein.* 10.7Form of Performance-Based Restricted Stock Unit Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-TermIncentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 30, 2014 and filed on July 3, 2014 and incorporatedby reference herein.* 10.8Form of Performance-Based Share Unit Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan,filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 1, 2015 and filed on July 8, 2015 and incorporated by referenceherein.* 10.9Form of Performance-Based Share Unit Agreement for Named Executive Officers for the EXCO Resources, Inc. Amended and Restated 2005Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 1, 2015 and filed on July 8, 2015 andincorporated by reference herein.* 10.10Form of Performance-Based Share Unit Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan,filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 1, 2016 and filed on July 6, 2016 and incorporated by referenceherein.* 10.11Form of Performance-Based Share Unit Agreement for Named Executive Officers for the EXCO Resources, Inc. Amended and Restated 2005Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 1, 2016 and filed on July 6, 2016 andincorporated by reference herein.* 10.12Fourth Amended and Restated EXCO Resources, Inc. Severance Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No.001-32743), dated March 16, 2011 and filed on March 22, 2011 and incorporated by reference herein.* 10.13Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No.001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.* 139Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.10.14Amendment Number One to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s AnnualReport on Form 10-K (File No. 001-32743) for 2009 filed on February 24, 2010 and incorporated by reference herein.* 10.15Amendment Number Two to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., effective as of May 22, 2014, filed asan Exhibit to EXCO’s Current Report on Form 8-K, dated May 22, 2014 and filed on May 29, 2014 and incorporated by reference herein.* 10.16Amendment Number Three to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., effective as of December 4, 2015,filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated December 4, 2015 and filed on December 10, 2015 and incorporated byreference herein.* 10.17Amendment Number Four to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., effective as of November 28, 2017,filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 28, 2017 and filed on December 4, 2017 and incorporated byreference herein.* 10.18Letter Agreement, dated March 28, 2007, with OCM Principal Opportunities Fund IV, L.P. and OCM EXCO Holdings, LLC, filed as anExhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated byreference herein. 10.19Amendment Number One to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an exhibit toEXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 4, 2009 and filed on June 10, 2009 and incorporated by referenceherein.* 10.20Amendment Number Two to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, dated as of October 6,2011, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated October 6, 2011 and filed on October 7, 2011and incorporated by reference herein.* 10.21Amendment Number Three to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, dated as of June 11, 2013,filed as an Exhibit to EXCO's Current Report on Form 8-K, dated June 11, 2013 and filed on June 12, 2013 and incorporated by referenceherein.* 10.22EXCO Resources, Inc. 2017-2018 Key Employee Incentive Plan, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for theQuarter Ended September 30, 2017 filed on November 7, 2017 and incorporated by reference herein.* 10.23Form of Retention Bonus Agreement for Key Employees, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the QuarterEnded September 30, 2017 filed on November 7, 2017 and incorporated by reference herein.* 10.24Form of Incentive Payment Agreement, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended September 30,2017 filed on November 7, 2017 and incorporated by reference herein.* 10.25Joint Development Agreement, dated August 14, 2009, by and among BG US Production Company, LLC, EXCO Operating Company, LPand EXCO Production Company, LP, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated August 11,2009 and filed on August 17, 2009 and incorporated by reference herein. 10.26Amendment to Joint Development Agreement, dated February 1, 2011, by and among BG US Production Company, LLC and EXCOOperating Company, LP, filed as an Exhibit to EXCO’s Annual Report on Form 10-K (File No. 001-32743) for 2010 filed February 24, 2011and incorporated by reference herein. 10.27Amendment to Joint Development Agreement, dated October 14, 2014, by and among BG US Production Company, LLC and EXCOOperating Company, LP, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2014 filed on February 25, 2015 and incorporatedby reference herein. 10.28Joint Development Agreement, dated as of June 1, 2010, by and among EXCO Production Company (PA), LLC, EXCO ProductionCompany (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed asan Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7, 2010 and incorporated byreference herein. 140Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.10.29Amendment to Joint Development Agreement, dated February 4, 2011, by and among EXCO Production Company (PA), LLC, EXCOProduction Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA),LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K (File No. 001-32743) for 2010 filed February 24, 2011 and incorporatedby reference herein. 10.30Amendment to Joint Development Agreement, dated October 14, 2014, by and among EXCO Production Company (PA), LLC, EXCOProduction Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA),LLC, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2014 filed on February 25, 2015 and incorporated by reference herein. 10.31Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC, dated June 1, 2010, by and amongEXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s CurrentReport on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein. 10.32Amendment to Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC, dated October 14,2014, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an Exhibit toEXCO's Annual Report on Form 10-K for 2014 filed on February 25, 2015 and incorporated by reference herein. 10.33Second Amended and Restated Limited Liability Company Agreement of Appalachia Midstream, LLC, dated June 1, 2010, by and amongEXCO Holding (PA), Inc., BG US Production Company, LLC and Appalachia Midstream, LLC, filed as an Exhibit to EXCO’s CurrentReport on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein. 10.34Amendment to Second Amended and Restated Limited Liability Company Agreement of Appalachia Midstream, LLC (n/k/a EXCOAppalachia Midstream, LLC), dated October 14, 2014, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC andEXCO Appalachia Midstream, LLC, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2014 filed on February 25, 2015 andincorporated by reference herein. 10.35Letter Agreement, dated June 1, 2010 and effective as of May 9, 2010, by and between EXCO Holding (PA), Inc. and BG US ProductionCompany, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7,2010 and incorporated by reference herein. 10.36Guaranty, dated May 9, 2010, by BG Energy Holdings Limited in favor of EXCO Holding (PA), Inc., EXCO Production Company (PA),LLC and EXCO Production Company (WV), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), datedJune 1, 2010 and filed on June 7, 2010 and incorporated by reference herein. 10.37Performance Guaranty, dated May 9, 2010, by EXCO Resources, Inc. in favor of BG US Production Company, LLC, filed as an Exhibit toEXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7, 2010 and incorporated by referenceherein. 10.38Guaranty, dated June 1, 2010, by BG North America, LLC in favor of (i) EXCO Production Company (PA), LLC, EXCO ProductionCompany (WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC and EXCO Holding (PA), Inc, filed as anExhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7, 2010 and incorporated byreference herein. 10.39Guaranty, dated June 1, 2010, by EXCO Resources, Inc., in favor of: (i) BG Production Company (PA), LLC, BG Production Company(WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC and BG US Production Company, LLC, filed as an Exhibitto EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7, 2010 and incorporated by referenceherein. 10.40Amended and Restated Credit Agreement, dated as of July 31, 2013, among EXCO Resources, Inc., as Borrower, certain subsidiaries ofBorrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO'sCurrent Report on Form 8-K, dated as of August 19, 2013 and filed on August 23, 2013 and incorporated by reference herein. 10.41First Amendment to Amended and Restated Credit Agreement, dated as of August 28, 2013, among EXCO Resources, Inc., as Borrower,certain subsidiaries of Borrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed asan Exhibit to EXCO's Current Report on Form 8-K, dated as of August 28, 2013 and filed on September 4, 2013 and incorporated byreference herein.141Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. 10.42Second Amendment to Amended and Restated Credit Agreement, dated as of July 14, 2014, by and among EXCO Resources, Inc., asBorrower, certain subsidiaries of Borrower, as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as AdministrativeAgent, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated as of July 14, 2014 and filed on July 18, 2014 and incorporated byreference herein. 10.43Third Amendment to Amended and Restated Credit Agreement, dated as of October 21, 2014, by and among EXCO Resources, Inc., asBorrower, certain subsidiaries of Borrower, as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as AdministrativeAgent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated October 21, 2014 and filed on October 27, 2014 and incorporatedby reference herein. 10.44Fourth Amendment to Amended and Restated Credit Agreement, dated as of February 6, 2015, among EXCO Resources, Inc., as Borrower,certain subsidiaries of Borrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed asan Exhibit to EXCO's Current Report Form 8-K, dated as of February 6, 2015 and filed on February 12, 2015 and incorporated by referenceherein. 10.45Fifth Amendment to Amended and Restated Credit Agreement, dated July 27, 2015, among EXCO Resources, Inc., as Borrower, certainsubsidiaries of Borrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as anExhibit to EXCO's Current Report on Form 8-K, dated as of July 27, 2015 and filed July 28, 2015 and incorporated by reference herein. 10.46Sixth Amendment to Amended and Restated Credit Agreement, dated as of October 19, 2015, among EXCO Resources, Inc., as Borrower,certain subsidiaries of Borrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed asan Exhibit to EXCO's Current Report on Form 8-K, dated as of October 19, 2015 and filed on October 22, 2015 and incorporated byreference herein. 10.47Seventh Amendment to Amended and Restated Credit Agreement, dated as of March 15, 2017, among EXCO Resources, Inc., as borrower,certain subsidiaries of borrower, as guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as administrative agent, filed asan Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 and incorporated by referenceherein. 10.48Eighth Amendment to Amended and Restated Credit Agreement, dated as of September 29, 2017, by and among EXCO Resources, Inc.,certain of its subsidiaries, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto, filed as an Exhibit to EXCO’sCurrent Report on Form 8-K, dated as of September 29, 2017 and filed on October 5, 2017 and incorporated by reference herein. 10.49Ninth Amendment to Amended and Restated Credit Agreement, dated as of November 20, 2017, among EXCO Resources, Inc., as borrower,certain subsidiaries of borrower, as guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as administrative agent, filed asan Exhibit to EXCO’s Current Report on Form 8-K, dated November 20, 2017 and filed on November 27, 2017 and incorporated byreference herein. 10.50Forbearance Agreement, dated as of December 20, 2017, by and among EXCO Resources, Inc., the subsidiary guarantors party thereto,JPMorgan Chase Bank, N.A., as administrative agent and the RBL Supporting Lenders filed as an Exhibit to EXCO’s Current Report onForm 8-K, dated December 15, 2017 filed December 21, 2017 and incorporated by reference herein. 10.51Limited Consent, dated as of September 1, 2016, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors,the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Quarterly Report onForm 10-Q for the Quarter Ended September 30, 2016 filed on November 2, 2016 and incorporated by reference herein. 10.52Limited Consent, dated as of December 30, 2016, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, asGuarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's CurrentReport on Form 8- K, dated as of December 30, 2016 and filed on January 6, 2017 and incorporated by reference herein. 10.53Term Loan Credit Agreement, dated as of October 19, 2015, by and among EXCO Resources, Inc., as Borrower, certain subsidiaries ofBorrower, as Guarantors, the lenders party thereto, and Wilmington Trust, National Association, as Administrative Agent and CollateralTrustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated as of October 19, 2015 and filed on October 22, 2015 andincorporated by reference herein. 10.54Form of Joinder Agreement to Term Loan Credit Agreement, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated as ofNovember 4, 2015 and filed on November 11, 2015 and incorporated by reference herein.142Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. 10.55First Amendment to Term Loan Credit Agreement, dated as of March 15, 2017, by and among EXCO Resources, Inc., as borrower, certainsubsidiaries of borrower, as guarantors, the lenders party thereto, and Wilmington Trust, National Association, as administrative agent andcollateral trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 andincorporated by reference herein. 10.561.75 Lien Term Loan Credit Agreement, dated as of March 15, 2017, by and among EXCO Resources, Inc., as borrower, certain subsidiariesof borrower, as guarantors, the lenders party thereto, and Wilmington Trust, National Association, as administrative agent and collateraltrustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 and incorporated byreference herein. 10.57First Amendment to 1.75 Lien Term Loan Credit Agreement, dated as of April 4, 2017, by and among EXCO Resources, Inc., as borrower,certain subsidiaries of borrower, as guarantors, the lenders party thereto, and Wilmington Trust, National Association, as administrativeagent and collateral trustee, filed on May 10, 2017 as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31,2017 and incorporated by reference herein. 10.58Second Amendment to 1.75 Lien Term Loan Credit Agreement, dated as of April 14, 2017, by and among EXCO Resources, Inc., asborrower, certain subsidiaries of borrower, as guarantors, the lenders party thereto, and Wilmington Trust, National Association, asadministrative agent and collateral trustee, filed on May 10, 2017 as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the QuarterEnded March 31, 2017 and incorporated by reference herein. 10.59Forbearance Agreement, dated as of December 19, 2017, by and among EXCO Resources, Inc., the subsidiary guarantors party thereto, andthe 1.75L Supporting Lenders filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated December 15, 2017 filed December 21,2017 and incorporated by reference herein. 10.60Forbearance Agreement, dated as of December 19, 2017, by and among EXCO Resources, Inc., the subsidiary guarantors party thereto, andthe Supporting Holders filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated December 15, 2017 filed December 21, 2017 andincorporated by reference herein. 10.61Intercreditor Agreement, dated as of October 26, 2015 and amended as of March 15, 2017, by and among EXCO Resources, Inc., JPMorganChase Bank, N.A., as original priority lien agent, and Wilmington Trust, National Association, as second lien collateral trustee and originalthird lien collateral agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017and incorporated by reference herein. 10.62Amended and Restated Collateral Trust Agreement, dated as of October 26, 2015 and amended and restated as of March 15, 2017, by andamong EXCO Resources, Inc., the grantors and guarantors from time to time party thereto, Wilmington Trust, National Association, asadministrative agent and collateral trustee, and the other parity lien debt representatives from time to time party thereto, filed as an Exhibitto EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 and incorporated by reference herein. 10.63Collateral Trust Agreement, dated as of March 15, 2017, by and among EXCO Resources, Inc., the grantors and guarantors from time to timeparty thereto, Wilmington Trust, National Association, as trustee under the second lien indenture and collateral trustee, and the other paritylien debt representatives from time to time party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017and filed on March 15, 2017 and incorporated by reference herein. 10.641.5 Lien Note Purchase Agreement, dated as of March 15, 2017, by and among EXCO Resources, Inc., certain of its subsidiaries, and thepurchaser signatories thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15,2017 and incorporated by reference herein. 10.65Second Lien Term Loan Purchase Agreement, dated as of March 15, 2017, by and among EXCO Resources, Inc., Hamblin Watsa InvestmentCounsel Ltd., as administrative agent under the Fairfax Second Lien Credit Agreement, Wilmington Trust, National Association, asadministrative agent under the Exchange Second Lien Credit Agreement, and each of the other undersigned parties thereto, filed as anExhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 and incorporated by reference herein. 10.66Amended and Restated Participation Agreement, dated July 25, 2016, by and among Admiral A Holding L.P., TE Admiral A Holding L.P.,Colt Admiral A Holding L.P. and EXCO Operating Company, LP., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July25, 2016 and filed on July 27, 2016 and incorporated by reference herein. 143Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.10.67Form of Director Indemnification Agreement, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), datedNovember 3, 2010 and filed on November 12, 2010 and incorporated by reference herein. 10.68MVC Letter Agreement, dated November 15, 2013, among BG US Production Company, LLC, BG US Gathering Company, LLC, EXCOOperating Company, LP, Azure Midstream Energy LLC (formerly known as TGGT Holdings, LLC) and TGG Pipeline, Ltd, filed as anExhibit to EXCO’s Current Report on Form 8-K, dated November 15, 2013 and filed on November 21, 2013 and incorporated by referenceherein. 10.69EXCO Resources, Inc. 2016 Management Incentive Plan, dated April 20, 2016, filed as an Exhibit to EXCO’s Current Report on Form 8-K,dated April 20, 2016 and filed on April 26, 2016 and incorporated by reference herein.* 10.70EXCO Resources, Inc. 2017 Management Incentive Plan, dated April 3, 2017, filed as an Exhibit to EXCO’s Current Report on Form 8-K,dated April 3, 2017 and filed on April 7, 2017 and incorporated by reference herein.* 10.71Retention Agreement, dated May 14, 2015, by and between Harold H. Jameson and EXCO Resources, Inc., filed as an Exhibit to EXCO’sCurrent Report on Form 8-K, dated May 14, 2015 and filed on May 20, 2015 and incorporated by reference herein.* 10.72Amended and Restated Retention Agreement, dated May 14, 2015, by and between Harold L. Hickey and EXCO Resources, Inc., filed as anExhibit to EXCO’s Current Report on Form 8-K, dated May 14, 2015 and filed on May 20, 2015 and incorporated by reference herein.* 10.73Services and Investment Agreement, dated as of March 31, 2015, by and among EXCO Resources, Inc. and Energy Strategic AdvisoryServices LLC, filed as an Exhibit to Amendment No. 1 to EXCO’s Current Report on Form 8-K/A, dated March 31, 2015 and filed on May26, 2015 and incorporated by reference herein. 10.74Acknowledgment of Amendment to Services and Investment Agreement, dated as of May 26, 2015, by and between EXCO Resources, Inc.and Energy Strategic Advisory Services LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 26, 2015 and filed onJune 1, 2015 and incorporated by reference herein. 10.75Amendment No. 2 to Services and Investment Agreement, dated as of September 8, 2015, by and between EXCO Resources, Inc. and EnergyStrategic Advisory Services LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 8, 2015 and filed onSeptember 9, 2015 and incorporated by reference herein. 10.76Nomination Letter Agreement, dated as of September 8, 2015, by and between EXCO Resources, Inc. and Energy Strategic AdvisoryServices LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 8, 2015 and filed on September 9, 2015 andincorporated by reference herein. 10.77Letter Agreement, dated as of November 9, 2017, by and between EXCO Resources, Inc. and Energy Strategic Advisory Services, LLC, filedherewith. 10.78Form of Backstop Commitment Fee Election Letter, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 andfiled on March 15, 2017 and incorporated by reference herein. 10.79Debtor-In-Possession Credit Agreement, dated as of January 22, 2018, among EXCO Resources, Inc., the Lenders party thereto, and HamblinWatsa Investment Counsel Ltd., as Administrative Agent filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 19,2018 filed January 25, 2018 and incorporated by reference herein. 10.80Agreement Regarding Settlement, dated January 29, 2018, by and among EXCO Resources, Inc., EXCO Holding (PA), Inc., EXCOResources (PA), LLC, EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, EXCO Operating Company, LP,EXCO Appalachia Midstream, LLC, BG US Production Company, LLC, BG North America, LLC, BG Production Company (PA), LLC, BGProduction Company (WV), LLC and SWEPI LP filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 22, 2018 filedMarch 1, 2018 and incorporated by reference herein. 144Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.10.81Settlement Agreement and Mutual Release, dated February 27, 2018, by and among EXCO Holding (PA), Inc., EXCO Production Company(PA), LLC, EXCO Production Company (WV), LLC, EXCO Resources (PA), LLC, BG Production Company (PA), LLC, BG ProductionCompany (WV), LLC and SWEPI LP filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 22, 2018 filed March 1,2018 and incorporated by reference herein. 10.82Membership Interest (BG PA) Transfer Agreement, dated February 27, 2018, by and among BG US Production Company, LLC, BGProduction Company (PA), LLC and EXCO Production Company (PA), LLC filed as an Exhibit to EXCO’s Current Report on Form 8-K,dated February 22, 2018 filed March 1, 2018 and incorporated by reference herein. 10.83Membership Interest (BG WV) Transfer Agreement, dated February 27, 2018, by and among BG US Production Company, LLC, BGProduction Company (WV), LLC and EXCO Production Company (WV), LLC filed as an Exhibit to EXCO’s Current Report on Form 8-K,dated February 22, 2018 filed March 1, 2018 and incorporated by reference herein. 10.84Membership Interest (ERPA) Transfer Agreement, dated February 27, 2018, by and among BG US Production Company, LLC, EXCOResources (PA), LLC and EXCO Holding (PA), Inc. filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 22, 2018filed March 1, 2018 and incorporated by reference herein. 10.85Membership Interest (Midstream) Transfer Agreement, dated February 27, 2018, by and among BG US Production Company, LLC, EXCOAppalachia Midstream, LLC and EXCO Holding (PA), Inc. filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 22,2018 filed March 1, 2018 and incorporated by reference herein. 10.86Termination and Release Agreement, dated February 27, 2018, by and among BG US Production Company, LLC, BG North America, LLC,BG Production Company (PA), LLC, BG Production Company (WV), LLC, EXCO Resources, Inc., EXCO Holding (PA), Inc., EXCOResources (PA), LLC, EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, EXCO Operating Company, LP andEXCO Appalachia Midstream, LLC. filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 22, 2018 filed March 1,2018 and incorporated by reference herein. 21.1Subsidiaries of registrant, filed herewith. 23.1Consent of KPMG LLP, filed herewith. 23.2Consent of Lee Keeling and Associates, Inc., filed herewith. 23.3Consent of Netherland, Sewell & Associates, Inc., filed herewith. 23.4Consent of Ryder Scott Company, L.P., filed herewith. 31.1Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Principal Executive Officer of EXCO Resources, Inc., filedherewith. 31.2Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Principal Financial Officer of EXCO Resources, Inc., filedherewith. 32.1Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Principal Executive Officer and Principal Financial Officer ofEXCO Resources, Inc., filed herewith. 99.12017 Report of Netherland, Sewell & Associates, Inc., filed herewith. 99.22017 Report of Ryder Scott Company, L.P., filed herewith. 101.INSXBRL Instance Document. 101.SCHXBRL Taxonomy Extension Schema Document. 101.CALXBRL Taxonomy Calculation Linkbase Document. 145Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.101.DEFXBRL Taxonomy Definition Linkbase Document. 101.LABXBRL Taxonomy Label Linkbase Document. 101.PREXBRL Taxonomy Presentation Linkbase Document. *These exhibits are management contracts. #Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. EXCO Resources, Inc. hereby undertakes tofurnish supplemental copies of any of the omitted schedules and exhibits upon request by the Securities and Exchange Commission.146Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 10.77Privileged and ConfidentialEnergy Strategic Advisory Services LLC200 Crescent Court, Suite 200Dallas, Texas 75201November 9, 2017EXCO Resources, Inc.12377 Merit DriveDallas, Texas 75251Attention: General CounselRe: Suspension of Services and Payments Ladies and Gentlemen: Reference is made to the Services and Investment Agreement, dated as of March 31, 2015, by and among Energy StrategicAdvisory Services LLC, a Delaware limited liability company (“ESAS”), and EXCO Resources, Inc., a Texas corporation (“EXCO”),as amended by the Acknowledgement of Amendment dated as of May 26, 2015 and by Amendment No. 2 dated as of September 8,2015 (as the same may be amended or amended and restated from time to time in accordance with its terms, the “Services andInvestment Agreement”), and the Letter Agreement Regarding Nomination of Designee to the Board of Directors of EXCO, datedSeptember 8, 2015, between ESAS and EXCO (as the same may be amended or amended and restated from time to time inaccordance with its terms, the “Nomination Agreement”). All capitalized terms used but not otherwise defined herein shall have therespective meanings set forth in the Services and Investment Agreement.Wilder’s ResignationAs we have discussed, Wilder intends to resign from the Board of Directors of EXCO and from his position as ExecutiveChairman of EXCO (the effective time of such resignation is referred to herein as the “Effective Time”).Suspension of Services and PaymentsESAS and EXCO agree that, during the Suspension Period (as defined below), (i) ESAS shall not be required to provide anyServices pursuant to the Services and Investment Agreement, and ESAS’ obligations to provide such Services shall be suspended, (ii)EXCO shall not be required to pay any Monthly Fee or any Incentive Payment in respect of the Suspension Period, and EXCO’sobligations to make such payments shall be suspended, and (iii) ESAS shall not have the right or obligation to nominate any person forelection to the Board of Directors of EXCO, and ESAS’ and EXCO’s rights and obligations under the Nomination Agreement shall besuspended. EXCO agreesSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.that it shall pay the Monthly Fee for all periods prior to the commencement of the Suspension Period in accordance with the Servicesand Investment Agreement.For purposes of this letter agreement, “Suspension Period” shall mean the period that begins at the Effective Time and ends onthe date that EXCO provides written notice to ESAS that EXCO elects to have ESAS recommence provision of the Services; providedhowever, that if EXCO commences chapter 11 proceedings, the Suspension period shall end on the earlier of the date that (i) EXCOprovides written notice to ESAS after entry of a Comfort Order (as defined below) that EXCO elects to have ESAS recommenceprovision of the Services and (ii) the effective date of a plan of reorganization with respect to EXCO that has been confirmed by abankruptcy court.For purposes of this letter agreement, a “Comfort Order” is an order entered by a bankruptcy court that provides that neitherESAS nor its Affiliates nor their respective representatives will be considered “insiders” of EXCO as a result of ESAS’ provision ofthe Services pursuant to the Services and Investment Agreement at EXCO’s election during the Suspension Period.WarrantsESAS and EXCO hereby agree that, effective as of the Effective Time, the four Warrants dated March 31, 2015 issued byEXCO to ESAS pursuant to the Services and Investment Agreement shall be forfeited and cancelled and EXCO shall have no furtherobligations under the Warrants.Comfort OrderEXCO shall use its reasonable best efforts to procure a Comfort Order as expeditiously as possible after the commencement ofchapter 11 proceedings, if any, with respect to EXCO and EXCO requests ESAS to recommence the provision of the Services.Affirmation of Services and Investment AgreementESAS and EXCO agree that the Services and Investment Agreement and the Nomination Agreement are in full force andeffect and that neither ESAS nor EXCO is in breach thereunder. Except as expressly modified herein, all of the terms and conditions ofthe Services and Investment Agreement and the Nomination Agreement shall remain in full force and effect. EXCO agrees that it willnot terminate the Services and Investment Agreement or the Nomination Agreement during the Suspension Period.MiscellaneousESAS represents and warrants to EXCO that this letter agreement has been duly and validly authorized by ESAS. EXCOrepresents and warrants to ESAS that this letter agreement has been duly and validly authorized by the independent members of theBoard of Directors of EXCO. This letter agreement shall be governed by, and construed in accordance with, the laws of the State ofTexas without regard to principles of conflicts of law. The terms of this letter agreement may not2Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.be amended, modified or supplemented, and waivers or consents to departures from the terms hereof may not be given, except by thewritten consent of all of the parties hereto. This letter agreement may be executed by the parties hereto in separate counterparts, each ofwhich when so executed and delivered shall be an original, but all such counterparts together shall constitute one and the sameinstrument. [Signature Page Follows] 3Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.If the foregoing accurately sets forth our understanding, please acknowledge by signing in the space provided below. Sincerely,ENERGY STRATEGIC ADVISORY SERVICES LLCBy: /s/ Jonathan Siegler Name: Jonathan Siegler Title: Chief Financial Officer Signature Page to Letter AgreementSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Agreed to and accepted as of the date set forth aboveEXCO RESOURCES, INC.By: /s/ Heather Lamparter Name: Heather Lamparter Title: VP, General Counsel & SecretarySignature Page to Letter AgreementSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXHIBIT 21.1LIST OF SUBSIDIARIES OF EXCO RESOURCES, INC.Name of Subsidiary State of IncorporationEXCO Appalachia Midstream, LLC DelawareEXCO GP Partners Old, LP DelawareEXCO Holding (PA), Inc. DelawareEXCO Holding MLP, Inc. TexasEXCO Land Company, LLC DelawareEXCO Mid-Continent MLP, LLC DelawareEXCO Operating Company, LP DelawareEXCO Partners GP, LLC DelawareEXCO Partners OLP GP, LLC DelawareEXCO Production Company (PA), LLC DelawareEXCO Production Company (WV), LLC DelawareEXCO Resources (PA), LLC DelawareEXCO Resources (XA), LLC DelawareEXCO Services, Inc. DelawareRaider Marketing GP, LLC DelawareRaider Marketing, LP DelawareBG Production Company (PA), LLC DelawareBG Production Company (WV), LLC DelawareSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 23.1Consent of Independent Registered Public Accounting FirmThe Board of Directors EXCO Resources, Inc.:We consent to the incorporation by reference in the registration statement on Form S-8 (Nos. 333-177900, 333-159930, 333-156086,333-132551, 333-146376 and 333-189262) and Form S-3 (Nos. 333-169253, 333-192898, 333-193660, 333-195126, 333-203549,333-207166, 333-208379 and 333-219641) of EXCO Resources, Inc. and subsidiaries (the Company) of our reports dated March 15,2018, with respect to the consolidated balance sheets of EXCO Resources, Inc. as of December 31, 2017 and 2016, and the relatedconsolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period endedDecember 31, 2017, and the related notes (collectively, the “consolidated financial statements”), and the effectiveness of internalcontrol over financial reporting as of December 31, 2017, which reports appear in the December 31, 2017 annual report on Form 10‑Kof EXCO Resources, Inc.Our report on the consolidated financial statements dated March 15, 2018, contains an explanatory paragraph that states theconsolidated financial statements have been prepared assuming that the Company will continue as a going concern. The accompanyingconsolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 1to the consolidated financial statements, the Company filed a voluntary petition for reorganization under Chapter 11 of the United StatesBankruptcy Code on January 15, 2018, which raises substantial doubt about the Company’s ability to continue as a going concern.Management's plans in regard to this matter are also described in Note 1. The consolidated financial statements do not include anyadjustments that might result from the outcome of this uncertainty./s/ KPMG LLPDallas, TexasMarch 15, 2018Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 23.2LEE KEELING AND ASSOCIATES, INC.INTERNATIONAL PETROLEUM CONSULTANTS115 West 3rd Street, Suite 700Tulsa, Oklahoma 74103-3410(918) 587-5521(918) 587-2881 (Fax)www.lkaengineers.comCONSENT OF INDEPENDENT PETROLEUM ENGINEERSAs independent petroleum engineers, Lee Keeling and Associates, Inc. hereby consents to all references to our firm included inor made part of this EXCO Resources, Inc. Annual Report on Form 10‑K for the year ended December 31, 2017 and further consents tothe incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-159930, 333-156086, 333-132551, 333-146376,333-177900 and 333-189262) and on Form S-3 (Nos. 333-193660, 333-203549, 333-207166, 333-208379 and 333-219641) of EXCOResources, Inc. of information from our reserve reports dated January 8, 2016, January 6, 2015 and January 8, 2014 on the estimatedproved oil and natural gas reserve quantities of EXCO Resources, Inc. and certain of its consolidated subsidiaries presented as ofDecember 31, 2015, 2014 and 2013./s/ Lee Keeling and Associates, Inc. LEE KEELING AND ASSOCIATES, INC.Tulsa, OklahomaMarch 15, 2018Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 23.3CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTSWe hereby consent to the incorporation by reference in the Registration Statements (Nos. 333‑159930, 333-156086, 333-132551, 333-146376, 333-177900, and 333-189262) on Form S-8 and on Form S-3 (Nos. 333-193660, 333-203549, 333-207166, 333-208379 and 333-219641) of EXCOResources, Inc. (the "Company") of the reference to Netherland, Sewell & Associates, Inc. and the inclusion of our reports dated January 23,2018, January 10, 2017, and January 21, 2016, in the Annual Report on Form 10-K for the year ended December 31, 2017, of the Company and itssubsidiaries, filed with the Securities and Exchange Commission.NETHERLAND, SEWELL & ASSOCIATES, INC./s/ C.H. (Scott) Rees IIIBy: C.H. (Scott) Rees III, P.E.Chairman and Chief Executive OfficerDallas, TexasMarch 15, 2018Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document isintended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions statedin the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digitaldocument.Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXHIBIT 23.4TBPE REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-08491100 LOUISIANA SUITE 4600HOUSTON, TEXAS 77002-5294TELEPHONE (713) 651-9191CONSENT OF RYDER SCOTT COMPANY, L.P.We have issued our report dated January 8, 2018 on estimates of proved reserves, future production and incomeattributable to certain leasehold interest of EXCO Resources, Inc. (“EXCO”) as of December 31, 2017. As independent oil and gasconsultants, we hereby consent to the inclusion of our report and the information contained therein and information from our priorreserve reports referenced in this Annual Report on Form 10-K of EXCO (this “Annual Report”) and to all references to our firm inthis Annual Report. We hereby also consent to the incorporation by reference of such reports and the information contained thereinin the Registration Statements of EXCO on Forms S-8 (File Nos. 333-159930, 333-156086, 333-132551, 333-146376, 333-177900and 333-189262) and on Form S-3 (File Nos. 333-193660, 333-203549, 333-207166, 333-208379 and 333-219641)./s/ Ryder Scott Company, L.P.RYDER SCOTT COMPANY, L.P.TBPE Firm Registration No. F-1580Houston, TexasMarch 15, 2018SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 31.1CERTIFICATIONI, Harold L. Hickey, the Principal Executive Officer of EXCO Resources, Inc., certify that:1.I have reviewed this Annual Report on Form 10-K of EXCO Resources, Inc.;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared;b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles;c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; andd)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely tomaterially affect, the registrant’s internal control over financial reporting; and5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; andb)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting. Date:March 15, 2018/s/ Harold L. Hickey Harold L. Hickey Chief Executive Officer and PresidentSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 31.2CERTIFICATIONI, Tyler Farquharson, the Principal Financial Officer of EXCO Resources, Inc., certify that:1.I have reviewed this Annual Report on Form 10-K of EXCO Resources, Inc.;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared;b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles;c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; andd)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely tomaterially affect, the registrant’s internal control over financial reporting; and5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; andb)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting.Date:March 15, 2018/s/ Tyler Farquharson Tyler Farquharson Vice President, Chief Financial Officer and TreasurerSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 32.1CERTIFICATION PURSUANT TO18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), eachof the undersigned officers of EXCO Resources, Inc. (the “Company”) in their capacity as Principal Executive Officer and Principal Financial Officer,respectively, does hereby certify, to such officer’s knowledge, that:The Annual Report on Form 10-K for the year ended December 31, 2017 (the “Form 10-K”) of the Company fully complies with the requirements ofSection 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended, and the information contained in the Form 10-K fairly presents, inall material respects, the financial condition and results of operations of the Company as of, and for, the periods presented in the Form 10-K.Date:March 15, 2018/s/ Harold L. Hickey Harold L. Hickey Chief Executive Officer and President /s/ Tyler Farquharson Tyler Farquharson Vice President, Chief Financial Officer and TreasurerThe foregoing certification is being furnished as an exhibit to the Form 10-K pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of theSarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as partof the Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of theCompany, whether made before or after the date hereof, regardless of any general incorporation language in such filing.Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.January 23, 2018 Exhibit 99.1Mr. Harold L. HickeyEXCO Resources, Inc.12377 Merit Drive, Suite 1700Dallas, Texas 75251Dear Mr. Hickey:In accordance with your request, we have estimated the proved developed reserves and future revenue, as of December 31, 2017, to the EXCOResources, Inc. (EXCO) interest in certain gas properties located in Louisiana, Pennsylvania, and Texas. We completed our evaluation on or aboutthe date of this letter. It is our understanding that the proved reserves estimated in this report constitute approximately 88 percent of all provedreserves owned by EXCO. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S.Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB AccountingStandards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report hasbeen prepared for EXCO's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of thisreport are appropriate for such purpose.We estimate the gross (100 percent) gas reserves and the net gas reserves and future net revenue to the EXCO interest in these properties, as ofDecember 31, 2017, to be: Gas Reserves (MMCF) Future Net Revenue (M$) Gross Present WorthCategory (100)% Net Total at 10% Proved Developed Producing 2,138,221.4 476,991.6 520,720.6 327,728.0Proved Developed Non-Producing 53,847.7 22,158.1 30,730.7 21,291.7 Total Proved Developed 2,192,069.1 499,149.7 551,451.3 349,019.7Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. These properties no longer producecommercial volumes of condensate.Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Asrequested, proved undeveloped, probable, and possible reserves that may exist for these properties have not been included. The estimates ofreserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed tointerests in undeveloped acreage.Gross revenue is EXCO's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is afterdeductions for EXCO's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but beforeconsideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth,which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted orundiscounted, should not be construed as being the fair market value of the properties.Gas prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in theperiod January through December 2017. The average Henry Hub spot price of $2.976 per MMBTU is adjusted for energy content, transportationfees, and market differentials. All prices are heldSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.constant throughout the lives of the properties. The average adjusted gas price weighted by production over the remaining lives of the properties is$2.547 per MCF.Operating costs used in this report are based on operating expense records of EXCO. These costs include the per-well overhead expensesallowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costshave been divided into per-well costs and per-unit-of-production costs. Headquarters general and administrative overhead expenses of EXCO areincluded to the extent that they are covered under joint operating agreements for the operated properties. An economic projection is included in theproved developed producing category to account for the fees associated with the portion of EXCO's firm transportation contracts allocated to theproved developed properties in Louisiana. For all other areas, we have made no investigation of any firm transportation contracts that may be inplace and no adjustments have been made to our estimates of future revenue to account for such contracts. Operating costs are not escalated forinflation.Capital costs used in this report were provided by EXCO and are based on authorizations for expenditure and actual costs from recent activity.Capital costs are included as required for workovers and production equipment. Based on our understanding of future development plans, a reviewof the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonmentcosts used in this report are EXCO's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costsand abandonment costs are not escalated for inflation.For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or conditionof the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do notinclude any costs due to such possible liability.We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the EXCO interest.Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections arebased on EXCO receiving its net revenue interest share of estimated future gross production.The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oiland gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible;probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimatesof reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance.In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to,that the properties will be developed consistent with current development plans as provided to us by EXCO, that the properties will be operated ina prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover thereserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenuestherefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties ofsupply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptionsmade while preparing this report.For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data,production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated usingdeterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil andGas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geosciencemethods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriateand necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation,there are uncertainties inherent in the interpretation ofSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.The data used in our estimates were obtained from EXCO, public data sources, and the nonconfidential files of Netherland, Sewell & Associates,Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties orindependently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimatespresented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.Matthew T. Dalka, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since2013 and has over 7 years of prior industry experience. William J. Knights, a Licensed Professional Geoscientist in the State of Texas, has beenpracticing consulting petroleum geoscience at NSAI since 1991 and has over 10 years of prior industry experience. We are independent petroleumengineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingentbasis. Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699 /s/ C.H. (Scott) Rees III By: C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer /s/ Matthew Dalka /s/ William J. KnightsBy: By: Matthew Dalka, P.E. 125306 William J. Knights, P.G. 1532 Petroleum Engineer Vice President Date Signed: January 23, 2018 Date Signed: January 23, 2018MTD:DCCPlease be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital documentis intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditionsstated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede thedigital document.Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also included issupplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) theFASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and DisclosureInterpretations.(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options topurchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees,recording fees, legal costs, and other costs incurred in acquiring properties.(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions(depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interestand thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support provedreserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:(i)Same geological formation (but not necessarily in pressure communication with the reservoir of interest);(ii)Same environment of deposition;(iii)Similar geological structure; and(iv)Same drive mechanism.Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscositygreater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state itusually contains sulfur, metals, and other non-hydrocarbons.(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that,when produced, is in the liquid phase at surface pressure and temperature.(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (fromthe geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minorcompared to the cost of a new well; and(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means notinvolving a well.Supplemental definitions from the 2007 Petroleum Resources Management System:Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time ofthe estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to berecovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for marketconditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones inexisting wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored withrelatively low expenditure compared to the cost of drilling a new well.Definitions - Page 1 of 7Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storingthe oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities andother costs of development activities, are costs incurred to:(i)Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specificdevelopment drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extentnecessary in developing the proved reserves.(ii)Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of wellequipment such as casing, tubing, pumping equipment, and the wellhead assembly.(iii)Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices,and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.(iv)Provide improved recovery systems.(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible.As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of agroup of several fields and associated facilities with a common ownership may constitute a development project.(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue thatexceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined atthe terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulativeproduction as of that date.(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered tohave prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and afteracquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment andfacilities and other costs of exploration activities, are:(i)Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries andother expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to asgeological and geophysical or "G&G" costs.(ii)Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for titledefense, and the maintenance of land and lease records.(iii)Dry hole contributions and bottom hole contributions.(iv)Costs of drilling and equipping exploratory wells.(v)Costs of drilling exploratory-type stratigraphic test wells.(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive ofoil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or astratigraphic test well as those items are defined in this section.(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.Definitions - Page 2 of 7Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structuralfeature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening imperviousstrata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated asa single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localizedgeological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.(16) Oil and gas producing activities.(i)Oil and gas producing activities include:(A)The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and originallocations;(B)The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas fromsuch properties;(C)The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including theacquisition, construction, installation, and maintenance of field gathering and storage systems, such as:(1)Lifting the oil and gas to the surface; and(2)Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and(D)Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewablenatural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outletvalve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminalpoint for the production function as:a.The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or amarine terminal; andb.In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to apurchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, amarine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that aresaleable in the state in which the hydrocarbons are delivered.(ii)Oil and gas producing activities do not include:(A)Transporting, refining, or marketing oil and gas;(B)Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not havethe legal right to produce or a revenue interest in such production;(C)Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas canbe extracted; or(D)Production of geothermal steam.(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.(i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding provedplus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the totalquantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.Definitions - Page 3 of 7Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations ofavailable data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to defineclearly the area and vertical limits of commercial production from the reservoir by a defined project.(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than therecovery quantities assumed for probable reserves.(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technicaland commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results insuccessful similar projects.(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within thesame accumulation that may be separated from proved areas by faults with displacement less than formation thickness or othergeological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are incommunication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower thanthe proved area if these areas are in communication with the proved reservoir.(vi)Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and thepotential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir abovethe HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir thatdo not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties andpressure gradient interpretations.(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which,together with proved reserves, are as likely as not to be recovered.(i)When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimatedproved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantitiesrecovered will equal or exceed the proved plus probable reserves estimates.(ii)Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of availabledata are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certaintycriterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communicationwith the proved reservoir.(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of thehydrocarbons in place than assumed for proved reserves.(iv)See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that couldreasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomesand their associated probabilities of occurrence.(20) Production costs.(i)Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs ofsupport equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. Theybecome part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:(A)Costs of labor to operate the wells and related equipment and facilities.(B)Repairs and maintenance.(C)Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.Definitions - Page 4 of 7Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)(D)Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.(E)Severance taxes.(ii)Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining,and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, theirdepreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion,and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the costof oil and gas produced along with production (lifting) costs identified above.(21) Proved area. The part of a property to which proved reserves have been specifically attributed.(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience andengineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs,and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right tooperate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are usedfor the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it willcommence the project within a reasonable time.(i)The area of the reservoir considered as proved includes:(A)The area identified by drilling and limited by fluid contacts, if any, and(B)Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to containeconomically producible oil or gas on the basis of available geoscience and engineering data.(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in awell penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonablecertainty.(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associatedgas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, orperformance data and reliable technology establish the higher contact with reasonable certainty.(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluidinjection) are included in the proved classification when:(A)Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, theoperation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes thereasonable certainty of the engineering analysis on which the project or program was based; and(B)The project has been approved for development by all necessary parties and entities, including governmental entities.(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The priceshall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as anunweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined bycontractual arrangements, excluding escalations based upon future conditions.(23) Proved properties. Properties with proved reserves.(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will berecovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceedthe estimate. A high degree of confidenceDefinitions - Page 5 of 7Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological,geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EURis much more likely to increase or remain constant than to decrease.(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been fieldtested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or inan analogous formation.(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as ofa given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonableexpectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas orrelated substances to market, and all permits and financing required to implement the project.Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until thosereservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from aknown accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas maycontain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end ofthe year:a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in theoperation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed inaccordance with paragraphs 932-235-50-3 through 50-11B:a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-endquantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing andproducing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Ifestimated development expenditures are significant, they shall be presented separately from estimated production costs.c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration offuture tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the propertiesinvolved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expensesfrom future cash inflows.e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating toproved oil and gas reserves.f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined byimpermeable rock or water barriers and is individual and separate from other reservoirs.Definitions - Page 6 of 7Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may beestimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscoveredaccumulations.(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells includegas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situcombustion.(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologiccondition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includestests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratorytype" if not drilled in a known area or "development type" if drilled in a known area.(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered fromnew wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain ofproduction when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility atgreater distances.(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they arescheduled to be drilled within five years, unless the specific circumstances, justify a longer time.From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentallysensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination mustalways take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extensionbeyond five years should be the exception, and not the rule.Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extendpast five years include, but are not limited to, the following:Ÿ The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimumnumber of wells necessary to maintain the lease generally would not constitute significant development activities);Ÿ The company's historical record at completing development of comparable long-term projects;Ÿ The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;Ÿ The extent to which the company has followed a previously adopted development plan (for example, if a company has changed itsdevelopment plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typicallywould not be appropriate); andŸ The extent to which delays in development are caused by external factors related to the physical operating environment (for example,restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources todevelop properties with higher priority).(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injectionor other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the samereservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technologyestablishing reasonable certainty.(32) Unproved properties. Properties with no proved reserves.Definitions - Page 7 of 7Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO RESOURCES, INC.EstimatedFuture Reserves and IncomeAttributable to CertainLeasehold InterestsSEC ParametersAs ofDecember 31, 2017/s/ Michael F. StellMichael F. Stell, P.E.TBPE License No. 56416Advising Senior Vice President[SEAL]RYDER SCOTT COMPANY, L.P.TBPE Firm Registration No. F-1580RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.TBPE REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-08491100 LOUISIANA SUITE 4600HOUSTON, TEXAS 77002-5294TELEPHONE (713) 651-9191January 8, 2018EXCO Resources, Inc.12377 Merit Drive, Suite 1700Dallas, Texas 75251Gentlemen:At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, futureproduction, and income attributable to certain leasehold interests of EXCO Resources, Inc. (EXCO) as of December 31, 2017. Thesubject properties are located in the state of Texas. The reserves and income data were estimated based on the definitions anddisclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of FederalRegulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SECregulations). Our third party study, completed on January 5, 2018 and presented herein, was prepared for public disclosure byEXCO in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.The properties evaluated by Ryder Scott account for a portion of EXCO’s total net proved reserves as of December 31,2017. Based on information provided by EXCO, the third party estimate conducted by Ryder Scott addresses 100 percent of thetotal proved developed net liquid hydrocarbon reserves and 1.9 percent of the total proved developed net gas reserves or 11.7percent of the total proved developed net reserves on a barrel of oil equivalent, BOE basis, (wherein natural gas is converted to oilequivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent).The estimated reserves and future net income amounts presented in this report, as of December 31, 2017, are related tohydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on thefirst-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required bythe SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes ofreserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantitiespresented in this report. The results of this study are summarized as follows.SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO Resources, Inc. – SEC ParametersJanuary 8, 2018Page 2SEC PARAMETERSEstimated Net Reserves and Income DataCertain Leasehold Interests ofEXCO Resources, Inc.As of December 31, 2017 Total Proved Developed ProducingNet Remaining Reserves Oil/Condensate – Barrels 9,412,144Gas – MMcf 9,872 Income Data ($M) Future Gross Revenue $394,380Deductions 173,600Future Net Income (FNI) $220,780 Discounted FNI @ 10% $132,497Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis”expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reservesare located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).The estimates of the reserves, future production, and income attributable to properties in this report were prepared using theeconomic software package ARIESTM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. Theprogram was used at the request of EXCO. Ryder Scott has found this program to be generally acceptable, but notes that certainsummaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized.Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties,also due to rounding. The rounding differences are not material.The future gross revenue is after the deduction of production taxes and gas and oil transportation expenses (other revenue).The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, abandonment costs and variableoperating costs that are shown as “Other” costs. The future net income is before the deduction of state and federal income taxesand general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include anyadjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 96 percent and gasreserves account for the remaining 4 percent of total future gross revenue from proved reserves.The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compoundedmonthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results areshown in summary form as follows.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO Resources, Inc. – SEC ParametersJanuary 8, 2018Page 3 Discounted Future Net Income ($M) As of December 31, 2017Discount Rate Total Percent Proved 5 $165,328 15 $111,246 20 $96,487 25 $85,668 The results shown above are presented for your information and should not be construed as our estimate of fair marketvalue.Reserves Included in This ReportThe proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’sRegulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum ReservesDefinitions” is included as an attachment to this report.The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves StatusDefinitions and Guidelines” in this report.No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. Theproved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economicallyproducible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve anassessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than theestimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliablegeologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree ofuncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unprovedreserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possiblereserves to denote progressively increasing uncertainty in their recoverability. At EXCO’s request, this report addresses only theproved reserves attributable to the properties evaluated herein.Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, canbe estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves includedherein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when basedon deterministic methods, as a “high degree of confidence that the quantities will be recovered.”Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or aseconomic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience(geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR)with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates ofproved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical oreconomic risks. Therefore, the proved reserves included in this report are estimates onlyRYDER SCOTT COMPANY PETROLEUM CONSULTANTSSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO Resources, Inc. – SEC ParametersJanuary 8, 2018Page 4and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs relatedthereto, could be more or less than the estimated amounts.EXCO’s operations may be subject to various levels of governmental controls and regulations. These controls andregulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce, drillingand production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies includingincome tax and are subject to change from time to time. Such changes in governmental regulations and policies may causevolumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from theestimated quantities.The estimates of proved reserves presented herein were based upon a detailed study of the properties in which EXCOowns an interest; however, we have not made any field examination of the properties. No consideration was given in this report topotential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages,if any, caused by past operating practices.Estimates of ReservesThe estimation of reserves involves two distinct determinations. The first determination results in the estimation of thequantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with thoseestimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generallyaccepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-basedmethods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by thereserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method orcombination of methods which in their professional judgment is most appropriate given the nature and amount of reliablegeoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics ofthe reservoir being evaluated, and the stage of development or producing maturity of the property.In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this datamay indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range inthe quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of thereserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discreteincremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is thecategorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimatedquantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actuallyrecovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reservesthat are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to berecovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered thanprobable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plusprobable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions asnoted above.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO Resources, Inc. – SEC ParametersJanuary 8, 2018Page 5Estimates of reserves quantities and their associated reserve categories may be revised in the future as additionalgeoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reservecategories may also be revised due to other factors such as changes in economic conditions, results of future operations, effectsof regulation by governmental agencies or geopolitical or economic risks as previously noted herein.The proved reserves for the properties that we evaluated were estimated by performance methods. All of the provedproducing reserves attributable to producing wells and/or reservoirs that we evaluated were estimated by decline curve analysiswhich utilized extrapolations of historical production data available through mid-December 2017, in those cases where such datawere considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by EXCO or obtained from publicdata sources and were considered sufficient for the purpose thereof.To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider manyfactors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical andengineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, andforecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipatedto be economically producible from a given date forward based on existing economic conditions including the prices and costs atwhich economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future pricesreceived for the sale of production and the operating costs and other costs relating to such production may increase or decreasefrom those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted fromconsideration in making this evaluation.EXCO has informed us that they have furnished us all of the material accounts, records, geological and engineering data,and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we haverelied upon data furnished by EXCO with respect to property interests owned, production and well tests from examined wells,normal direct costs of operating the wells or leases, salt water disposal expenses, other costs such as transportation and/orprocessing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costsafter salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural andisochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for itsreasonableness; however, we have not conducted an independent verification of the data furnished by EXCO. We consider thefactual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future netrevenues herein.In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for thepurpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare theestimates of reserves herein. The proved reserves included herein were determined in conformance with the United StatesSecurities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references toRegulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reservespresented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.Future Production RatesFor wells currently on production, our forecasts of future production rates are based on historical performance data. If noproduction decline trend has been established, future production rates were heldRYDER SCOTT COMPANY PETROLEUM CONSULTANTSSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO Resources, Inc. – SEC ParametersJanuary 8, 2018Page 6constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. Anestimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was usedas the basis for estimating future production rates.Test data and other related information were used to estimate the anticipated initial production rates for those wells that arenot currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished byEXCO. Wells that are not currently producing may start producing earlier or later than anticipated in our estimates due tounforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, theavailability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.The future production rates from wells currently on production or wells that are not currently producing may be more or lessthan estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surfacefacilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowablesor other constraints set by regulatory bodies.Hydrocarbon PricesThe hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-monthperiod prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbonproducts sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments,were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmeticaverage as previously described.EXCO furnished us with the above mentioned average prices in effect on December 31, 2017. These initial SEChydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to thegeographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials asdescribed herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area includedin the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.The product prices that were actually used to determine the future gross revenue for each property reflect adjustments tothe benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” Thedifferentials used in the preparation of this report were furnished to us by EXCO. The differentials furnished by EXCO werereviewed by us for their reasonableness using information furnished by EXCO for this purpose.In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred toherein as the “average realized prices.” The average realized prices shown in the table below were determined from the total futuregross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SECdisclosure requirements for each of the geographic areas included in the report.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO Resources, Inc. – SEC ParametersJanuary 8, 2018Page 7Geographic AreaProductPriceReferenceAverageBenchmarkPricesAverageRealizedPricesNorth America United StatesOil/CondensateWTI Cushing$51.34/bbl$47.69/bbl GasHenry Hub$2.98/MMBTU$1.80/McfThe effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individualproperty evaluations.CostsOperating costs for the leases and wells in this report were furnished by EXCO and are based on the operating expensereports of EXCO and include only those costs directly applicable to the leases or wells. The operating costs include a portion ofgeneral and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include anappropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties includethe COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operatingcosts furnished by EXCO were reviewed by us for their reasonableness using information furnished by EXCO for this purpose. Nodeduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not chargeddirectly to the leases or wells.Development costs were furnished to us by EXCO and are based on authorizations for expenditure for the proposed workor actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us fortheir reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost ofabandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates ofthe net abandonment costs furnished by EXCO were accepted without independent verification.Current costs used by EXCO were held constant throughout the life of the properties.Standards of Independence and Professional QualificationRyder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting servicesthroughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; andCalgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firmand the large number of clients for which we provide services, no single client or job represents a material portion of our annualrevenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separateand independent from the operating and investment decision-making process of our clients. This allows us to bring the highest levelof independence and objectivity to each engagement for our services.Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused onthe subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on thesubject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participatingin ongoing continuing education.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.EXCO Resources, Inc. – SEC ParametersJanuary 8, 2018Page 8Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have receivedprofessional accreditation in the form of a registered or certified professional engineer’s license or a registered or certifiedprofessional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.We are independent petroleum engineers with respect to EXCO. Neither we nor any of our employees have any financialinterest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimatesof reserves for the properties which were reviewed.The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists andengineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible foroverseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.Terms of UsageThe results of our third party study, presented in report form herein, were prepared in accordance with the disclosurerequirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC byEXCO.EXCO makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, EXCO has certainregistration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K isincorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 andForm S-8 of EXCO of the references to our name as well as to the references to our third party report for EXCO, which appears inthe December 31, 2017 annual report on Form 10-K of EXCO. Our written consent for such use is included as a separate exhibit tothe filings made with the SEC by EXCO.We have provided EXCO with a digital version of the original signed copy of this report letter. In the event there are anydifferences between the digital version included in filings made by EXCO and the original signed report letter, the original signedreport letter shall control and supersede the digital version.The data and work papers used in the preparation of this report are available for examination by authorized parties in ouroffices. Please contact us if we can be of further service.Very truly yours,RYDER SCOTT COMPANY, L.P.TBPE Firm Registration No. F-1580/s/ Michael F. StellMichael F. Stell, P.E.TBPE License No. 56416Advising Senior VicePresident[SEAL]MFS (DPR)/plRYDER SCOTT COMPANY PETROLEUM CONSULTANTSSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Professional Qualifications of Primary Technical PersonThe conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineersfrom Ryder Scott Company, L.P. Mr. Michael F. Stell was the primary technical person responsible for overseeing the estimate ofthe reserves, future production and income.Mr. Stell, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1992, is an Advising Senior Vice President and isresponsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studiesworldwide. Before joining Ryder Scott, Mr. Stell served in a number of engineering positions with Shell Oil Company and LandmarkConcurrent Solutions. For more information regarding Mr. Stell’s geographic and job specific experience, please refer to the RyderScott Company website at www.ryderscott.com/Company/Employees.Mr. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of ScienceDegree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in theState of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineersrequires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics,which Mr. Stell fulfills. As part of his 2009 continuing education hours, Mr. Stell attended an internally presented 13 hours offormalized training as well as a day-long public forum relating to the definitions and disclosure guidelines contained in the UnitedStates Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, FinalRule released January 14, 2009 in the Federal Register. Mr. Stell attended an additional 15 hours of formalized in-house training aswell as an additional five hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEEPetroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods,procedures and software and ethics for consultants. As part of his 2010 continuing education hours, Mr. Stell attended an internallypresented six hours of formalized training and ten hours of formalized external training covering such topics as updates concerningthe implementation of the latest SEC oil and gas reporting requirements, reserve reconciliation processes, overviews of the variousproductive basins of North America, evaluations of resource play reserves, evaluation of enhanced oil recovery reserves, andethics training. For each year starting 2011 through 2017, as of the date of this report, Mr. Stell has 20 hours of continuingeducation hours relating to reserves, reserve evaluations, and ethics.Based on his educational background, professional training and over 30 years of practical experience in the estimation andevaluation of petroleum reserves, Mr. Stell has attained the professional qualifications for a Reserves Estimator and ReservesAuditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information”promulgated by the Society of Petroleum Engineers as of February 19, 2007.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.PETROLEUM RESERVES DEFINITIONSAs Adapted From:RULE 4-10(a) of REGULATION S-X PART 210UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)PREAMBLEOn January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oiland Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The“Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 ofRegulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifiesIndustry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to RegulationS-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for allfilings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010.Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for thecomplete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italicsherein).Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economicallyproducible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve anassessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than theestimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliablegeologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree ofuncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unprovedreserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possiblereserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31,2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gasreserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gasresources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unlesssuch information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.Reserves estimates will generally be revised only as additional geologic or engineering data become available or aseconomic conditions change.Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include allmethods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples ofsuch methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use ofmiscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleumtechnology continues to evolve.Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulationsare considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction methodapplied, or degree of processing prior to sale. ExamplesRYDER SCOTT COMPANY PETROLEUM CONSULTANTSSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.PETROLEUM RESERVES DEFINITIONSPage 2of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas,gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extractiontechnology and/or significant processing prior to sale.Reserves do not include quantities of petroleum being held in inventory.Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum fromdifferent reserves categories.RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economicallyproducible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, orthere must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production,installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement theproject.Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults untilthose reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that areclearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, ornegative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscoveredaccumulations).PROVED RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscienceand engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, fromknown reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time atwhich contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless ofwhether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must havecommenced or the operator must be reasonably certain that it will commence the project within a reasonable time.(i) The area of the reservoir considered as proved includes:(A) The area identified by drilling and limited by fluid contacts, if any, and(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with itand to contain economically producible oil or gas on the basis of available geoscience and engineering data.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.PETROLEUM RESERVES DEFINITIONSPage 3PROVED RESERVES (SEC DEFINITIONS) CONTINUED(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons(LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technologyestablishes a lower contact with reasonable certainty.(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential existsfor an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only ifgeoscience, engineering, or performance data and reliable technology establish the higher contact with reasonablecertainty.(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but notlimited to, fluid injection) are included in the proved classification when:(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in thereservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or otherevidence using reliable technology establishes the reasonable certainty of the engineering analysis on which theproject or program was based; and(B) The project has been approved for development by all necessary parties and entities, including governmentalentities.(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to bedetermined. The price shall be the average price during the 12-month period prior to the ending date of the period coveredby the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month withinsuch period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINESAs Adapted From:RULE 4-10(a) of REGULATION S-X PART 210UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)andPETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)Sponsored and Approved by:SOCIETY OF PETROLEUM ENGINEERS (SPE)WORLD PETROLEUM COUNCIL (WPC)AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)Reserves status categories define the development and producing status of wells and reservoirs. Reference should bemade to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the followingreserves status definitions are based on excerpts from the original documents (direct passages excerpted from theaforementioned SEC and SPE-PRMS documents are denoted in italics herein).DEVELOPED RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:Developed oil and gas reserves are reserves of any category that can be expected to be recovered:(i) Through existing wells with existing equipment and operating methods or in which the cost of the requiredequipment is relatively minor compared to the cost of a new well; and(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if theextraction is by means not involving a well.Developed Producing (SPE-PRMS Definitions)While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.Developed Producing ReservesDeveloped Producing Reserves are expected to be recovered from completion intervals that are open and producing at thetime of the estimate.Improved recovery reserves are considered producing only after the improved recovery project is in operation.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINESPage 2Developed Non-ProducingDeveloped Non-Producing Reserves include shut-in and behind-pipe reserves.Shut-InShut-in Reserves are expected to be recovered from:(1)completion intervals which are open at the time of the estimate, but which have not started producing;(2)wells which were shut-in for market conditions or pipeline connections; or(3)wells not capable of production for mechanical reasons.Behind-PipeBehind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completionwork or future re-completion prior to start of production.In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a newwell.UNDEVELOPED RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves asfollows:Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells onundrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that arereasonably certain of production when drilled, unless evidence using reliable technology exists that establishesreasonable certainty of economic producibility at greater distances.(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has beenadopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify alonger time.(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which anapplication of fluid injection or other improved recovery technique is contemplated, unless such techniques havebeen proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSource: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Source: EXCO RESOURCES INC, 10-K, March 15, 2018Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.

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