Exco Resources (EXCO) 10-Q 15 May 18 2018 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 09, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
Entity Registrant Name	EXCO RESOURCES INC
Entity Central Index Key	316,300
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		21,630,260

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 65,830	$ 39,597
Restricted cash	9,832	15,271
Accounts receivable, net:
Oil and natural gas	77,679	55,692
Joint interest	32,986	30,570
Other	1,915	1,976
Derivative financial instruments - commodity derivatives	0	1,150
Other current assets	17,127	23,574
Total current assets	205,369	167,830
Equity investments	4,736	14,181
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	149,322	118,652
Proved developed and undeveloped oil and natural gas properties	3,239,618	3,107,566
Accumulated depletion	(2,770,278)	(2,752,311)
Oil and natural gas properties, net	618,662	473,907
Other property and equipment, net and other non-current assets	39,345	21,274
Goodwill	163,155	163,155
Total assets	1,031,267	840,347
Current liabilities:
Accounts payable and accrued liabilities	49,365	68,277
Revenues and royalties payable	42,727	207,956
Accrued interest payable	1,140	27,637
Current portion of asset retirement obligations	600	600
Current maturities of long-term debt	473,364	1,362,500
Total current liabilities	567,196	1,666,970
Deferred income taxes	0	4,518
Derivative financial instruments - common share warrants	0	1,950
Asset retirement obligations and other long-term liabilities	23,853	13,108
Liabilities subject to compromise	1,496,871	0
Commitments and contingencies
Shareholders’ equity:
Common shares, par value $0.001, 260,000,000 shares authorized; 21,670,109 shares issued and 21,630,464 shares outstanding at March 31, 2018; 21,670,186 shares issued and 21,630,541 shares outstanding at December 31, 2017	22	22
Additional paid-in capital	3,540,017	3,539,422
Accumulated deficit	(4,589,060)	(4,378,011)
Treasury shares, at cost; 39,645 shares at March 31, 2018 and December 31, 2017	(7,632)	(7,632)
Total shareholders’ equity	(1,056,653)	(846,199)
Total liabilities and shareholders’ equity	$ 1,031,267	$ 840,347

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Mar. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.001	$ 0.001
Common stock, authorized shares	260,000,000	260,000,000
Common stock, shares issued	21,670,109	21,670,186
Common stock, shares outstanding	21,630,464	21,630,541
Treasury stock, shares	39,645	39,645

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues:
Oil	$ 16,297	$ 16,192
Natural gas	68,849	53,164
Purchased natural gas and marketing	5,318	7,173
Total revenues	90,464	76,529
Costs and expenses:
Oil and natural gas operating costs	7,908	8,498
Production and ad valorem taxes	3,996	3,435
Gathering and transportation	19,976	27,353
Purchased natural gas	4,115	6,452
Depletion, depreciation and amortization	18,206	11,508
Accretion of liabilities	342	212
General and administrative	8,527	4,415
Gain on Appalachia JV Settlement	(119,477)	0
Other operating items	134	1,069
Total costs and expenses	(56,273)	62,942
Operating income	146,737	13,587
Other income (expense):
Interest expense, net	(9,173)	(19,952)
Gain (loss) on derivative financial instruments - commodity derivatives	(615)	15,533
Gain on derivative financial instruments - common share warrants	183	6,004
Loss on restructuring and extinguishment of debt	0	(6,272)
Other income	22	4
Equity income	179	317
Reorganization items, net	(352,900)	0
Total other expense	(362,304)	(4,366)
Income (loss) before income taxes	(215,567)	9,221
Income tax expense (benefit)	(4,518)	1,028
Net income (loss)	$ (211,049)	$ 8,193
Basic:
Net income (loss) (in dollars per share)	$ (9.64)	$ 0.44
Weighted average common shares outstanding	21,902	18,726
Diluted:
Net income (loss) (in dollars per share)	$ (9.64)	$ 0.44
Weighted average common shares and common share equivalents outstanding	21,902	18,749

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating Activities:
Net income (loss)	$ (211,049)	$ 8,193
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax expense	(4,518)	1,028
Depletion, depreciation and amortization	18,206	11,508
Equity-based compensation	448	(2,382)
Accretion of liabilities	342	212
Income from equity investments	(179)	(317)
(Gain) loss on derivative financial instruments - commodity derivatives	615	(15,533)
Cash receipts (payments) of commodity derivative financial instruments	535	(4,459)
Gain on derivative financial instruments - common share warrants	(183)	(6,004)
Amortization of deferred financing costs and discount on debt issuance	4,166	4,402
Gain on Appalachia JV Settlement	(119,477)	0
Non-cash reorganization items, net	339,049	0
Loss on restructuring and extinguishment of debt	0	6,272
Paid in-kind interest expense	(21,078)	0
Other non-operating items	0	(21)
Effect of changes in:
Accounts receivable	(17,801)	24,431
Other current assets	9,266	772
Accounts payable and other liabilities	49,910	(22,906)
Net cash provided by operating activities	48,252	5,196
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment	(66,856)	(11,857)
Property acquisitions	14,832	0
Net changes in amounts due to joint ventures	0	(3,723)
Net cash used in investing activities	(52,024)	(15,580)
Financing Activities:
Borrowings under DIP Credit Agreement	156,406	0
Borrowings under EXCO Resources Credit Agreement	0	25,000
Repayments under EXCO Resources Credit Agreement	(126,401)	(253,592)
Proceeds received from issuance of 1.5 Lien Notes, net	0	295,530
Payments on Second Lien Term Loans	0	(10,512)
Debt financing costs and other	(5,439)	(18,636)
Net cash provided by financing activities	24,566	37,790
Net increase in cash, cash equivalents and restricted cash	20,794	27,406
Cash, cash equivalents and restricted cash at beginning of period	54,868	20,218
Cash, cash equivalents and restricted cash at end of period	75,662	47,624
Supplemental Cash Flow Information:
Cash interest payments	14,800	14,778
Income tax payments	0	0
Supplemental non-cash investing and financing activities:
Capitalized equity-based compensation	147	356
Capitalized interest	1,065	1,290
Net assets acquired on Appalachia JV Settlement, excluding cash and cash equivalents	$ 114,268	$ 0

Consolidated Statements Of Chan

Consolidated Statements Of Changes In Shareholders' Equity - USD ($) shares in Thousands, $ in Thousands	Total	Common Shares	Treasury Shares	Additional Paid-in Capital	Accumulated Deficit
Beginning balance (in shares) at Dec. 31, 2016		18,916	(40)
Beginning balance at Dec. 31, 2016	$ (871,906)	$ 19	$ (7,632)	$ 3,538,080	$ (4,402,373)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Equity-based compensation	(1,730)			(1,730)
Net income (loss)	8,193				8,193
Ending balance (in shares) at Mar. 31, 2017		18,916	(40)
Ending balance at Mar. 31, 2017	(865,443)	$ 19	$ (7,632)	3,536,350	(4,394,180)
Beginning balance (in shares) at Dec. 31, 2017		21,670	(40)
Beginning balance at Dec. 31, 2017	(846,199)	$ 22	$ (7,632)	3,539,422	(4,378,011)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Equity-based compensation	595			595
Net income (loss)	(211,049)				(211,049)
Ending balance (in shares) at Mar. 31, 2018		21,670	(40)
Ending balance at Mar. 31, 2018	$ (1,056,653)	$ 22	$ (7,632)	$ 3,540,017	$ (4,589,060)

Organization And Basis Of Prese

Organization And Basis Of Presentation	3 Months Ended
	Mar. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and basis of presentation	Organization and basis of presentation Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “EXCO,” “EXCO Resources,” “Company,” “we,” “our,” and “us” 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 onshore U.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 areas including Texas, Louisiana and the Appalachia region. The following is a brief discussion of our producing regions: • East Texas and North Louisiana The East Texas and North Louisiana regions are primarily comprised of our Haynesville and Bossier shale assets. We have a joint venture with a wholly owned subsidiary of Royal Dutch Shell, plc (“Shell”), covering an undivided 50% interest in the majority of our Haynesville and Bossier shale assets in East Texas and North Louisiana. The East Texas and North Louisiana regions also include certain assets outside of the joint venture in the Haynesville and Bossier shales. We serve as the operator for most of our properties in the East Texas and North Louisiana regions. • South Texas The 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 Texas region. • Appalachia The Appalachia region is primarily comprised of our Marcellus shale assets. We had a joint venture with Shell covering our Marcellus shale and other assets in the Appalachian 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 an entity that operates the Appalachia JV’s properties (“OPCO”), which was previously jointly owned by EXCO and Shell. 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 of mutual interest in the Appalachia region (“Appalachia JV Settlement”). As a result of the Appalachia JV Settlement, we acquired Shell’s interests in the Appalachia JV and OPCO. See further discussion of this transaction in “ Note 3. Acquisitions, divestitures and other significant events ”. The accompanying Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017 , Condensed Consolidated Statements of Operations, Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the three months ended March 31, 2018 and 2017 are for EXCO and its subsidiaries. The unaudited Condensed Consolidated Financial Statements and related footnotes are presented in accordance with generally accepted accounting principles in the United States (“GAAP”). Certain reclassifications have been made to prior period information to conform to current period presentation. We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) for interim financial statements and in the opinion of management, such financial statements reflect all adjustments necessary to fairly present the consolidated financial position of EXCO as of March 31, 2018 and its results of operations and cash flows for the periods presented. These unaudited interim financial statements should be read in conjunction with our audited consolidated financial statements and related footnotes included in EXCO’s Annual Report on Form 10-K for the year ended December 31, 2017 , filed with the SEC on March 15, 2018 (“2017 Form 10-K”). In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures. The results of operations for the interim periods are not necessarily indicative of the results we expect for the full year. Chapter 11 Cases and Going Concern Assessment On January 15, 2018 (“Petition Date”), 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 and Raider Marketing GP, LLC (collectively, the “Filing Subsidiaries” and, together with the Company, the “Debtors”), filed voluntary petitions for relief under Chapter 11 of the 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 has 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 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 continue our operations without interruption during the 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 and uncertainties associated with Chapter 11 proceedings. 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 our operations, properties and capital plans included in this quarterly report on Form 10-Q may not accurately reflect our operations, properties and capital plans following the conclusion of the Chapter 11 Cases. We have not reached an agreement with our creditors for a plan of reorganization and continue to engage in discussions regarding the terms of a financial restructuring plan. In conjunction with this process, we will explore potential strategic alternatives to maximize value for the benefit of our stakeholders, which may include a sale of certain or substantially all of our assets under Section 363 of the Bankruptcy Code, a plan of reorganization to equitize certain indebtedness as an alternative to the sale process, or a combination thereof. 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, including actions of the Court and our creditors. The significant risks and uncertainties related to our liquidity and the Chapter 11 proceedings raise substantial doubt about our ability to continue as a going concern. We define liquidity as cash and restricted cash plus the unused borrowing base under our debtor-in-possession credit agreement (“Liquidity”). These Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. The accompanying Condensed Consolidated Financial Statements do not include any adjustments to reflect the possible future effects of this uncertainty on the recoverability or classification of recorded asset amounts or the amounts or classification of liabilities. Chapter 11 filing impact on creditors and shareholders We have filed schedules and statements with the Court setting forth, among other things, the assets and liabilities of each of the Debtors, subject to the assumptions filed in connection therewith. These schedules and statements may be subject to further amendment or modification after filing. Certain holders of pre-petition claims that are not governmental units were required to file proofs of claim by the deadline for general claims, which was set by the Court as April 15, 2018 (“Bar Date”). Differences between amounts scheduled by the Debtors and claims by creditors are being investigated and will be reconciled and resolved to within an immaterial amount in connection with the claims resolution process. In light of the expected number of creditors, the claims resolution process may take considerable time to complete and likely will continue after the Debtors emerge from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently asserted. Under 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 property under a plan of reorganization. The ultimate recovery for creditors, if any, will not be determined until confirmation and implementation of a plan of reorganization. The outcome of the Chapter 11 Cases remains uncertain at this time and, as a result, we cannot accurately estimate the amounts or value of distributions that creditors may receive. We believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 Cases and the holders of our existing common shares will be entitled to a limited recovery, if any. Automatic stay Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against 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 or enforce 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-petition claim are stayed. Impact on indebtedness As of the Petition Date, we had approximately $1.4 billion in principal amount of indebtedness, including approximately: (i) $126.4 million outstanding under our previous revolving credit agreement (“EXCO Resources Credit Agreement”), (ii) $317.0 million outstanding under our senior secured 1.5 lien notes due March 20, 2022 (“1.5 Lien Notes”), (iii) $708.9 million outstanding under our senior secured 1.75 lien term loans due October 26, 2020 (“1.75 Lien Term Loans”), (iv) $17.2 million outstanding under our senior secured second lien term loans due October 26, 2020 (“Second Lien Term Loans”), (v) $131.6 million outstanding under our senior unsecured notes due September 15, 2018 (“2018 Notes”), and (vi) $70.2 million outstanding under our senior unsecured notes due April 15, 2022 (“2022 Notes”). The commencement of the Chapter 11 Cases described above constituted 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 be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments are subject to the applicable provisions of the Bankruptcy Code. As a result of the Chapter 11 proceedings, the Court may limit post-petition interest on debt that may be under secured or unsecured. On January 22, 2018, we closed a debtor-in-possession credit agreement (“DIP Credit Agreement”) with lenders including affiliates of Fairfax Financial 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 B Facility”, and together with the Revolver A Facility, the “DIP Facilities”). Proceeds from the DIP Facilities were used to repay all obligations outstanding under the EXCO Resources Credit Agreement and will provide additional liquidity to fund our operations during the Chapter 11 process. As of March 31, 2018 , we had $156.4 million in outstanding indebtedness and $81.6 million of available borrowing capacity under the DIP Facilities. See further discussion of the DIP Credit Agreement in “ Note 8. Debt ”. 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. 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 Subsidiaries to avoid limitations on the use of our income tax net operating loss carryforwards and certain other tax attributes by imposing certain notice procedures and transfer restrictions on the trading of our equity securities. In general, the order applies to any person that, directly or indirectly, beneficially owns (or would beneficially own as a result of a proposed transfer) at least 4.5% of our outstanding common shares (“Substantial Shareholder”), and requires that each Substantial Shareholder file with the Court and serve us with notice of such status. Under the order, prior to any proposed acquisition or disposition of equity securities that 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 or entity becoming a Substantial Shareholder, 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 a material risk of adversely affecting our ability to utilize such tax attributes. Executory contracts Subject to certain exceptions, under the Bankruptcy Code, the Company and the Filing Subsidiaries may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Court and fulfillment of certain other conditions. The rejection of an executory contract or unexpired 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 to a general unsecured claim against us or the applicable Filing Subsidiaries for damages caused by such rejection. The assumption of an executory contract or unexpired lease generally requires the Company and the Filing Subsidiaries to cure existing monetary or other defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Any description of the treatment of an executory contract or unexpired lease with the Company or any of the Filing Subsidiaries, including any description of the obligations under any such executory contract or unexpired lease, is qualified by and subject to any rights we have with respect to executory contracts and unexpired leases under the Bankruptcy Code. During March 2018, the Court approved the rejection of the following executory contracts: • Firm transportation agreements with Acadian Gas Pipeline System (“Acadian”), which required us to transport 325,000 Mmbtu per day on the Acadian Gas Pipeline System or pay reservation charges through October, 31, 2025; • Natural gas sales agreements with Enterprise Products Operating LLC (“Enterprise”), which required us to sell 75,000 Mmbtu per day of natural gas to Enterprise or incur certain costs through October 31, 2025; • Firm transportation agreements with Regency Intrastate Gas Systems LLC (“Regency”), which required us to either transport 237,500 Mmbtu per day of natural gas or pay reservation charges through January 31, 2020; • Marketing agreement with a subsidiary of Chesapeake Energy Corporation (“Chesapeake”), which required us to allow Chesapeake to purchase natural gas from certain wells in North Louisiana through 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 through November 30, 2020. On March 1, 2018, the Company and the Filing Subsidiaries filed a motion to reject an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certain gathering systems through November 30, 2018. On May 8, 2018, the motion was abated pending the filing of an adversary proceeding. Accounting during bankruptcy We have applied Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”), in the preparation of these Condensed Consolidated Financial Statements. For periods subsequent to the Chapter 11 filings, ASC 852 requires the financial statements to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred during the bankruptcy proceedings, including losses related to executory contracts that have been approved for rejection by the Court, and adjustments to the carrying value of certain indebtedness are recorded as “Reorganization items, net” on the Condensed Consolidated Statement of Operations. In addition, pre-petition obligations that may be impacted by the Chapter 11 process have been classified on the Condensed Consolidated Balance Sheet as of March 31, 2018 as “Liabilities subject to compromise.” Liabilities subject to compromise The accompanying Condensed Consolidated Balance Sheet as of March 31, 2018 includes amounts classified as liabilities subject to compromise, which represent liabilities that are anticipated to be allowed as claims in the Chapter 11 Cases. These amounts represent our current estimate of known or potential obligations to be resolved in connection with the Chapter 11 proceedings, and may differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material. Liabilities subject to compromise includes amounts related to the rejection of various executory contracts. Additional amounts may be included in liabilities subject to compromise in future periods if additional executory contracts or unexpired leases are rejected. Conversely, to the extent that executory contracts or unexpired leases are not rejected and are instead assumed, liabilities associated therewith would constitute post-petition liabilities which will be satisfied in full under a plan of reorganization. The nature of certain potential claims arising under the Debtors’ executory contracts and unexpired leases has not been determined at this time, and therefore, such claims are not reasonably estimable at this time and may be material. The following table summarizes the components of liabilities subject to compromise included on the Condensed Consolidated Balance Sheet as of March 31, 2018: (in thousands) March 31, 2018 Current maturities of long-term debt $ 927,917 Accrued interest payable 34,281 Accounts payable, accrued expenses and other liabilities 118,710 Liabilities related to rejected executory contracts 415,963 Liabilities subject to compromise $ 1,496,871 As of March 31, 2018, the principal and accrued interest associated with the DIP Credit Agreement and 1.5 Lien Notes were not classified as liabilities subject to compromise as a result of the adequate protection approved by the Court and our current estimates of the recoverability of claims related to these instruments. Reorganization items, net We have incurred significant expenses associated with the Chapter 11 process, primarily (i) the acceleration of deferred financing costs, debt discounts and deferred reductions in carrying value associated with debt instruments previously accounted for as a troubled debt restructuring pursuant to ASC 470-60, Troubled Debt Restructuring by Debtor s, (ii) adjustments for estimated allowable claims related to executory contracts approved for rejection by the Court, and (iii) legal and professional fees incurred subsequent to the Petition Date related to the restructuring process. These costs, which are being expensed as incurred, significantly impact our results of operations. The following table summarizes the components included in “Reorganization items, net” in our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018: (in thousands) Three Months Ended March 31, 2018 Legal and professional fees $ 13,850 Deferred financing costs, debt discounts and deferred reductions in carrying value 29,853 Rejection of executory contracts 309,197 Reorganization items, net $ 352,900 Interest expense We have discontinued recording interest on debt instruments classified as liabilities subject to compromise as of the Petition Date. The contractual interest on liabilities subject to compromise not reflected in the Condensed Consolidated Statement of Operations was approximately $21.9 million , representing interest expense from the Petition Date through March 31, 2018. The cash interest rate of 12.5% was utilized in the determination of contractual interest expense that would have been incurred under the 1.75 Lien Term Loans for the period subsequent to the Petition Date.

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Significant accounting policies	Significant accounting policies We consider significant accounting policies to be those related to our estimates of proved reserves, oil and natural gas properties, derivatives, business combinations, equity-based compensation, goodwill, revenue recognition, asset retirement obligations and income taxes. The policies include significant estimates made by management using information available at the time the estimates were made. However, these estimates could change materially if different information or assumptions were used. These policies and others are summarized in our 2017 Form 10-K. In addition, see further discussion of our application of ASC 852 as a result of the Chapter 11 Cases in “ Note 1. Organization and basis of presentation ”. Recent accounting pronouncements In February 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842) (“ASU 2016-02”). The main difference between the current requirement under GAAP and ASU 2016-02 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating 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). The liability 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. For income statement purposes, the FASB retained a dual model, requiring leases to be classified as either operating or finance leases. Operating leases will result in straight-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 the classification criteria and the accounting for sales-type and direct financing leases. ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and early adoption is permitted. ASU 2016-02 must be adopted using a modified retrospective transition, and provides for certain practical expedients. These transactions will require application of the new guidance at the beginning of the earliest comparative period presented. In January 2018, the FASB issued further guidance on the new lease standard in ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). ASU 2018-01 provides a practical expedient to exclude existing or expired land easements from the evaluation of leases under ASU 2016-02 if the easements were not previously accounted for as leases under the current guidance. We are currently assessing the potential impact of ASU 2016-02 and related clarifying updates and expect they will have an impact on our consolidated financial condition and results of operations upon adoption. We are currently unable to quantify the impact the standard will have 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 Emerging Issues 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 cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. ASU 2016-18 is effective for annual and interim periods beginning after December 15, 2017 and early adoption is permitted. We adopted ASU 2016-18 in the first quarter of 2018 utilizing retrospective application. The adoption resulted in an increase in reported investing cash flows of $4.4 million for the three months ended March 31, 2017 with a corresponding adjustment to the reported end of period cash balances. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017. Under ASU 2017-01, an entity must 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 similar assets. 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 a business includes, at a minimum, an input and a substantive process that together significantly contribute to the ability to create outputs. ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017. We adopted ASU 2017-01 in the first quarter of 2018 and will apply the guidance of ASU 2017-01 prospectively to future asset acquisitions, including the acquisitions as part of the Appalachia JV Settlement during the first quarter of 2018. In July 2017, the FASB issued ASU No. 2017-11, Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), Derivatives and Hedging (Topic 815): I. Accounting for Certain Financial Instruments with Down Round Features, II. Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception (“ASU 2017-11”). ASU 2017-11 revises the guidance for instruments with down round features in Subtopic 815-40, Derivatives and Hedging - Contracts in Entity’s Own Equity , which is considered in determining whether an equity-linked financial instrument qualifies for a scope exception from derivative accounting. An entity is still required to determine whether instruments would be classified in equity under the guidance in Subtopic 815-40 in determining whether they qualify for that scope exception. If they do qualify, freestanding instruments with down round features are no longer classified as liabilities. Our 2017 Warrants (as defined in “Note 7. Derivative financial instruments”) are required to be classified as liabilities under the current guidance due to their down round features. The amendments in Part I are required to be applied retrospectively to outstanding financial instruments with down round features. ASU 2017-11 is effective for annual and interim periods beginning after December 15, 2018, and early adoption is permitted, including adoption in an interim period. We are currently assessing the impact of ASU 2017-11; however, we believe that it could have an impact on our consolidated financial condition and results of operations if we determine the 2017 Warrants qualify for equity classification. However, we believe it is highly likely that our existing common shares as well as the 2017 Warrants will be canceled at the conclusion of our Chapter 11 Cases. In March 2018, the FASB issued ASU No. 2018-05, Income Taxes (Topic 740): Amendments to SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 118 (“ASU 2018-05”). The Amendments in this update add various SEC paragraphs pursuant to the issuance of SEC Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”). SAB 118 directs taxpayers to consider the implications of the Tax Cuts and Jobs Act (“Tax Act”) as provisional when it does not have the necessary information available, prepared, or analyzed in reasonable detail to complete its accounting for the change in the tax law. SAB 118 provides a one-year measurement period from a registrant’s reporting period that includes the Tax Act’s enactment date to allow the registrant sufficient time to obtain, prepare and analyze information to complete the required accounting under ASC 740. As described in the 2017 Form 10-K, we reflected the impact of the changes in rates on our deferred tax assets and liabilities at December 31, 2017, as we are required to reflect the change in the period in which the law is enacted. We are still analyzing certain aspects of the Tax Act, which could potentially affect 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 estimates provided herein, possibly materially, due to additional regulatory guidance, changes in interpretations and assumptions, and other actions as a result of the Tax Act. 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 the International Accounting Standards Board jointly issued this comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under GAAP. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised 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 or services. The FASB issued additional ASUs that primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectability, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017 and permits the use of either the retrospective or cumulative effect transition method. We adopted ASU 2014-09 and related updates in the first quarter of 2018 based on the modified retrospective method of adoption. The adoption of this standard did not have an impact on our consolidated financial condition and results of operations. We have implemented processes to ensure new contracts are reviewed for the appropriate accounting treatment and to generate the disclosures required under the new standard. Overview of marketing arrangements 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 under contracts using market sensitive pricing. The majority of our oil contracts are based on NYMEX pricing, which is typically calculated as the average of the daily closing prices of oil to be delivered one month in the future. We also 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 a type common within the industry, and we usually negotiate a separate contract for each area. Generally, we sell our oil to purchasers and refiners near the areas 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 in length from spot market sales of a single day to term agreements that may extend for a month or more. Our natural gas customers primarily include natural gas marketing companies. The natural gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market varies daily, reflecting changing market conditions. Revenue recognition under ASC 606 We use the sales method of accounting for oil and natural gas revenues. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes primarily on company-measured volume readings. We then adjust 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 March 31, 2018 and December 31, 2017 were not significant. We generally sell oil and natural gas under two types of agreements that are common in our industry. Both types of agreements include transportation charges. We evaluate whether we are the principal or the agent in each transaction. The first type of agreement is a net-back arrangement, under which we sell oil or natural gas at the wellhead and collect a price, net of the transportation costs incurred by the purchaser. The purchaser takes custody, title and risk of loss of the oil or natural gas at the wellhead. In this case, we record revenue when the control transfers to the purchaser at the wellhead based on the price received, net of the transportation costs. Under the second type of agreement, 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 transportation deduction. The purchaser takes custody, title, and risk of loss of the oil or natural gas at the specific delivery point. In this case, we are deemed to be the principal and the ultimate third-party purchaser is deemed to be the customer. We recognize revenue when control transfers to the purchaser at the specific delivery point based on the price received from the purchaser. The costs that we incur to transport the oil or natural gas are recorded as gathering and transportation expenses. As such, our computed realized prices include revenues that are recognized under two separate bases. Raider Marketing, LP (“Raider”) is a wholly owned subsidiary focused on the marketing of oil and natural gas. Raider purchases and resells natural gas from third-party producers, as well as oil and natural gas from operated wells in Texas and Louisiana, and charges a fee for marketing services to certain working interest owners in the related wells. Raider takes custody, title and risk of loss from the third-party producer upon the purchase of natural gas, then sells the natural gas to a separate third-party purchaser further downstream. The price paid for the purchase of natural gas from the third-party producer is not dependent on the price received from the ultimate purchaser. We are deemed to be the principal in these transactions. As such, third party purchases and sales are reported on a gross basis as “Purchased natural gas” expenses and “Purchased natural gas and marketing” revenues, respectively. The marketing fee charged by Raider to certain working interest owners in our operated wells is reported as “Purchased natural gas and marketing” revenues. Transaction price allocated to remaining performance obligations Our sales are short-term in nature with a contract term of one year or less. We have utilized the practical expedient in ASC 606-10-50-14 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Contract balances Under our oil and natural gas sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our oil and natural gas sales contracts do not give rise to contract assets or liabilities under ASC 606. Prior-period performance obligations We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil and natural gas sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three months ended March 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Acquisitions, Divestitures and

Acquisitions, Divestitures and Other Significant Events	3 Months Ended
	Mar. 31, 2018
Business Combinations [Abstract]
Business Combination Disclosure [Text Block]	Acquisitions, divestitures and other significant events Appalachia JV Settlement On January 26, 2018, we filed a motion in the Court to authorize the entry into a settlement agreement with a subsidiary of Shell to resolve arbitration regarding our 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, 2018 and we closed the settlement agreement on February 27, 2018. Under the terms of the Appalachia JV Settlement: • Shell transferred its interests to EXCO in each of BG Production Company (PA), LLC, BG Production Company (WV), LLC, OPCO, and Appalachia Midstream, LLC (“Appalachia Midstream”). On April 20, 2018, BG Production Company (PA), LLC legally changed its name to EXCO Production Company (PA) II, LLC and BG Production Company (WV), LLC legally changed its name to EXCO Production Company (WV) II, LLC; • Shell and EXCO terminated and considered to be fulfilled obligations and liabilities under certain specified agreements related to the Appalachia JV; • EXCO reconveyed its interests in certain leases, representing an interest in 364 net acres, that EXCO had previously acquired from Shell within the area 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 and remedies 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 in producing wells acquired was 26 net Mmcfe per day during December 2017. In addition, EXCO now owns 100% of OPCO and Appalachia Midstream subsequent to the settlement. Prior to the settlement, we accounted for our 50% ownership interests in OPCO and Appalachia Midstream as equity method investments. The entities associated with the Appalachia JV Settlement, including EXCO Production Company (PA) II, LLC, EXCO Production Company (WV) II, LLC, OPCO, and Appalachia Midstream, have not filed for relief under Chapter 11 of the Bankruptcy Code, and the operations of these entities are not expected to be affected by the Chapter 11 Cases. We accounted for the acquisitions in accordance with FASB ASC 805, Business Combinations . The following table presents a summary of the fair value of assets acquired and liabilities assumed as part of the Appalachia JV Settlement as of the closing date. (in thousands) Amount Assets acquired: Cash and cash equivalents $ 14,832 Accounts receivable, net 6,493 Other current assets 5,264 Unproved oil and natural gas properties 33,542 Proved developed and undeveloped oil and natural gas properties, net 72,548 Other assets 18,109 Liabilities assumed: Accounts payable and accrued liabilities (9,478 ) Asset retirement obligations (2,315 ) Other long-term liabilities (9,895 ) Fair value of net assets acquired $ 129,100 The fair value of the assets and liabilities acquired as part of the Appalachia JV Settlement of $129.1 million resulted in a gain of $119.5 million after remeasurement of our previously held equity interest in OPCO and Appalachia Midstream. As of the closing date, the carrying value of our equity investments in OPCO and Appalachia Midstream was $9.6 million . We performed a valuation of the assets and liabilities acquired as of the closing date. A summary of the key inputs are as follows: Working capital - The fair value approximated the carrying value for working capital including cash and cash equivalents, accounts receivable, other current assets, accounts payable and accrued liabilities. Oil and natural gas properties - The fair value allocated to unproved and proved oil and natural gas properties was $33.5 million and $72.5 million , respectively. The fair value of oil and natural gas properties was determined based on a discounted cash flow model of the estimated reserves. The estimated quantities of reserves utilized assumptions based on our internal geological, engineering data and financial data. We utilized NYMEX forward strip prices to value the reserves then applied various discount rates depending on the classification of reserves and other risk characteristics. Other assets - The fair value allocated to other assets was $18.1 million , which is primarily comprised of gas gathering assets held by Appalachia Midstream. The fair value of the gas gathering assets was determined based on transaction multiples of peer companies and a discounted cash flow model from our internally generated oil and natural gas reserves for the related properties. Asset retirement liabilities - The fair value allocated to asset retirement obligations was $2.3 million . These asset retirement obligations represent the present value of the estimated amount to be incurred to plug, abandon and remediate proved producing properties at the end of their productive lives, in accordance with applicable state laws. The fair value was determined based on a discounted cash flow model, which included assumptions of the estimated current abandonment costs, discount rate, inflation rate, and timing associated with the incurrence of these costs. Firm transportation contract - OPCO holds a contract that requires it to transport a minimum volume of natural gas or pay reservation charges. The performance obligations under the contract exceeded the future economic benefit to be received over the life of the contract. We calculated the fair value as the present value of the remaining unused commitments discounted at a rate consistent with market participants. The fair value of the liability was $12.1 million , including the current portion of $2.2 million and the long-term portion of $9.9 million . Pro forma results of operations - The following table reflects the unaudited pro forma results of operations if the Appalachia JV Settlement had occurred on January 1, 2017: Three Months Ended March 31, (in thousands except for per share data) 2018 2017 Oil and natural gas revenues $ 94,543 $ 83,557 Net income (loss) (209,789 ) 10,159 Basic earnings (loss) per share $ (9.58 ) $ 0.54 Diluted earnings (loss) per share $ (9.58 ) $ 0.54 Related party transactions - As noted previously, prior to the Appalachia JV Settlement, we accounted for our 50% ownership interests in OPCO and Appalachia Midstream as equity method investments. OPCO served as the operator of our wells in the Appalachia JV and we advanced funds to OPCO on an as needed basis. Additionally, there were service agreements between us and OPCO whereby we provide administrative and technical services for which we are reimbursed. Prior to the closing of the settlement, we had received $1.7 million under these agreements during 2018.

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2018
Asset Retirement Obligation [Abstract]
Asset retirement obligations	Asset retirement obligations The following is a reconciliation of our asset retirement obligations for the three months ended March 31, 2018 : (in thousands) Asset retirement obligations at beginning of period $ 12,017 Activity during the period: Liabilities incurred during the period — Revisions in estimated assumptions (1 ) Liabilities settled during the period (7 ) Adjustment to liability due to acquisitions (1) 2,315 Adjustment to liability due to divestitures (7 ) Accretion of discount 241 Asset retirement obligations at end of period 14,558 Less current portion 600 Long-term portion $ 13,958 (1) The increase in our asset retirement obligations during the three months ended March 31, 2018 is primarily due to additional interests in oil and natural gas properties acquired as part of the Appalachia JV Settlement. Our asset retirement obligations are determined using discounted cash flow methodologies based on inputs and assumptions developed by management. We do not have any assets that are legally restricted for purposes of settling asset retirement obligations.

Oil and Natural Gas Properties

Oil and Natural Gas Properties	3 Months Ended
	Mar. 31, 2018
Oil and Gas Property [Abstract]
Oil and natural gas properties	Oil and natural gas properties We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties (“collectively, the “full cost pool”). 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 to proved properties as a result of extensions or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. The majority of our undeveloped properties are held-by-production, which reduces the risk of impairment as a result of lease expirations. There were no impairments of unproved properties during the three months ended March 31, 2018 or 2017 . At the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs (“ceiling test”). The ceiling test involves comparing the net book value of the full cost 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 are required to record an impairment of our oil and natural gas properties. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our proved reserves by applying the average price as prescribed by the SEC, less estimated future expenditures (based on current costs) to develop and produce the proved reserves, discounted at 10% , plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects. During March 2018, the Court approved the rejection of certain executory contracts related to the sale, marketing and transportation of natural gas in the North Louisiana region. The rejection of these executory contracts has positively impacted the present value of our proved reserves. See further discussion of the rejection of executory contracts in “Note 1. Organization and basis of presentation”. The ceiling test for each period was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing twelve-month simple average spot prices at the first of the month for natural gas at Henry Hub (“HH”) and West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in 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) March 31, 2018 $ 53.49 $ 3.00 December 31, 2017 51.34 2.98 We did no t recognize an impairment to our proved oil and natural gas properties for the three months ended March 31, 2018 or for the three months ended March 31, 2017 . The possibility and amount of any future impairments 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, future capital expenditures and operating costs. As of March 31, 2018, our proved undeveloped reserves were limited to certain wells expected to be completed during 2018. Our recognition of proved undeveloped reserves continues to be affected by the uncertainty regarding our availability of capital required to develop these reserves. A significant amount of our proved undeveloped reserves that were previously reclassified to unproved remain economic at current prices, and we may report proved undeveloped reserves in the future if we determine we have the financial capability to execute a development plan. The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are inherent uncertainties in estimating quantities of proved reserves including projecting the future rates of production and the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data, and engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.

Earnings Per Share

Earnings Per Share	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Earnings per share	Earnings (loss) per share The following table presents the basic and diluted earnings (loss) per share computations, adjusted to give effect to our reverse share split, for the three months ended March 31, 2018 and 2017 : Three Months Ended March 31, (in thousands, except per share data) 2018 2017 Basic net income (loss) per common share: Net income (loss) $ (211,049 ) $ 8,193 Weighted average common shares outstanding 21,902 18,726 Net income (loss) per basic common share $ (9.64 ) $ 0.44 Diluted net income (loss) per common share: Net income (loss) $ (211,049 ) $ 8,193 Weighted average common shares outstanding 21,902 18,726 Dilutive effect of: Restricted shares and restricted share units — 23 Weighted average common shares and common share equivalents outstanding 21,902 18,749 Net income (loss) per diluted common share $ (9.64 ) $ 0.44 Basic net income (loss) per common share is based on the weighted average number of common shares outstanding during the period. In addition, warrants representing the right to purchase our common shares at an exercise price of $0.01 are included in our weighted average common shares outstanding and used in the computation of our basic net income (loss) per common share. Diluted net income (loss) per common share for the three months ended March 31, 2018 and 2017 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 share units, restricted share awards, warrants representing the right to purchase our common shares at an exercise price of $13.95 , and for the three months ended March 31, 2017 , warrants issued to Energy Strategic Advisory Services LLC (“ESAS”), whether exercisable or not. The computation of diluted net income (loss) per share excluded 12,640,295 and 3,232,222 antidilutive common share equivalents for the three months ended March 31, 2018 and 2017 , respectively. The antidilutive common share equivalents for the three months ended March 31, 2018 primarily related to the warrants representing the right to purchase our common shares at an exercise price of $13.95 . The antidilutive common share equivalents for the three months ended March 31, 2017 primarily related to warrants issued to ESAS.

Derivative Financial Instrument

Derivative Financial Instruments	3 Months Ended
	Mar. 31, 2018
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Derivative financial instruments	Derivative financial instruments Our derivative financial instruments are comprised of commodity derivatives and common share warrants. The table below presents the effect of derivative financial instruments on our Condensed Consolidated Balance Sheets: (in thousands) March 31, 2018 December 31, 2017 Current assets Derivative financial instruments - commodity derivatives $ — $ 1,150 Liabilities subject to compromise Derivative financial instruments - common share warrants $ (1,767 ) $ — Long-term liabilities Derivative financial instruments - common share warrants — (1,950 ) The table below presents the effect of derivative financial instruments on our Condensed Consolidated Statements of Operations. Three Months Ended March 31, (in thousands) 2018 2017 Gain (loss) on derivative financial instruments - commodity derivatives $ (615 ) $ 15,533 Gain on derivative financial instruments - common share warrants 183 6,004 Commodity derivative financial instruments We have historically entered into commodity derivative financial instruments to manage our exposure to commodity price fluctuations, protect our returns on investments and achieve a more predictable cash flow from operations. These transactions limit exposure to declines in commodity prices, but also limit the benefits we would realize if commodity prices increase. Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from, or cash disbursements to, our derivative 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 Condensed Consolidated Balance Sheets fair value amounts. At December 31, 2017 , we had outstanding swap contracts covering 3,650 Bbtu of natural gas at a weighted average strike price of $3.15 per Mmbtu. In January 2018, the counterparty to our remaining open swap contracts early terminated the outstanding contracts effective January 31, 2018. We received proceeds of $0.5 million for the settlement of these contracts in February 2018. As of March 31, 2018 , we did not have any outstanding commodity derivative financial instruments. Common share warrants In connection with the issuance of the 1.5 Lien Notes, on March 15, 2017, we issued warrants to the investors of the 1.5 Lien Notes representing the right to 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”), and warrants 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 purchase an 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 the Commitment Fee Warrants and Financing Warrants, collectively referred to as the “2017 Warrants”). On January 16, 2018, affiliates of Fairfax, which had previously been identified as a related party, surrendered all of their rights to the Commitment Fee, Amendment Fee and Financing Warrants. Their rights under the 2017 Warrants entitled them to purchase in aggregate up to 10,824,376 common shares at $13.95 per share and 1,725,576 common shares at $0.01 per share. Pursuant to the terms of the 2017 Warrants, the 2017 Warrants may not be exercised, subject to certain exceptions and limitations, if, as a result of such exercise, the holder or its affiliates would beneficially own, directly or indirectly, more than 50% of our outstanding common shares. Each of the 2017 Warrants has an exercise term 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 an anti-dilution adjustment in the event we issue common shares for consideration less than the market value of our common shares or exercise price of the Financing 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. The 2017 Warrants are accounted for as derivatives in accordance with FASB ASC 815, Derivatives and Hedging , (“ASC 815”), and are required to be classified as liabilities due to the types of anti-dilution adjustments. 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 2017 Warrants will be measured at fair value on a recurring basis until the date of exercise or the date of expiration. As a result of the change in the fair value of the 2017 Warrants, we recorded gains of $0.2 million and $6.0 million on the revaluation of the warrants during the three months ended March 31, 2018 and 2017, respectively, in “ Gain on derivative financial instruments - common share warrants ” on the Condensed Consolidated Statements of Operations. The gains were primarily due to a decrease in EXCO’s share price and the cancellation of warrants by affiliates of Fairfax.

Debt

Debt	3 Months Ended
	Mar. 31, 2018
Long-term Debt, Current and Noncurrent [Abstract]
Debt	Debt The carrying value of our total debt is summarized as follows: (in thousands) March 31, 2018 December 31, 2017 DIP Credit Agreement $ 156,406 $ — EXCO Resources Credit Agreement — 126,401 1.5 Lien Notes, net of unamortized discount 316,958 176,560 1.75 Lien Term Loans, net of unamortized discount 708,926 845,763 Second Lien Term Loans 17,246 23,543 2018 Notes, net of unamortized discount 131,576 131,345 2022 Notes 70,169 70,169 Deferred financing costs, net — (11,281 ) Total debt, net 1,401,281 1,362,500 Less amounts included in liabilities subject to compromise 927,917 — Current maturities of long-term debt $ 473,364 $ 1,362,500 As of December 31, 2017, we classified all of our outstanding indebtedness as a current liability as a result of agreements entered into in anticipation of events of default under certain debt agreements, as well as any outstanding debt with cross-default provisions, and an event of default under the Second Lien Term Loans. The commencement of the Chapter 11 Cases constituted an event of default that accelerated our obligations under the 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 be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement with respect to the debt instruments are subject to the applicable provisions of the Bankruptcy Code. As of the Petition Date, we adjusted the carrying value of our indebtedness to the estimated amount that will be allowed as claims in the Chapter 11 Cases. These amounts represent our current estimate and may materially differ from actual future settlement amounts paid. This resulted in expenses of $24.4 million for the acceleration of (i) deferred financing costs, (ii) debt discounts, and (iii) deferred reductions in carrying value associated with debt instruments previously accounted for as a troubled debt restructuring pursuant to ASC 470-60, which was classified as “Reorganization items, net” in our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018 . As discussed below, the proceeds from the DIP Facilities were used to repay all obligations under the EXCO Resources Credit Agreement and the EXCO Resources Credit Agreement was terminated. The financing costs of $5.4 million that were directly attributable to the DIP Credit Agreement were expensed as “Reorganization items, net” in our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018 . 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. We accrued interest on 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes through the Petition Date with no interest accrued subsequent to the filings. The 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes have been reclassified as “Liabilities subject to compromise” on the Condensed Consolidated Balance Sheet as of March 31, 2018. As of March 31, 2018, the carrying value for each of our debt instruments approximates the principal amount. As of March 31, 2018, the principal and accrued interest associated with the DIP Credit Agreement and 1.5 Lien Notes were not classified as liabilities subject to compromise as a result of the adequate protection approved by the Court and our current estimate of the recoverability of claims related to these debt instruments. DIP Credit Agreement On January 18, 2018, the Court entered into an interim order that authorized us to enter into the DIP Credit Agreement. On January 22, 2018, we closed the DIP Credit Agreement, which includes the Revolver A Facility in an aggregate principal amount of $125.0 million and the Revolver B Facility in an aggregate principal amount of $125.0 million with the DIP Lenders. Hamblin Watsa Investment Counsel Ltd. is the administrative agent (“DIP Agent”) for the DIP Credit Agreement. The proceeds of the DIP Facilities may be used in accordance with the DIP Credit Agreement to (i) repay obligations outstanding under the EXCO Resources Credit Agreement, (ii) pay for operating expenses incurred during the Chapter 11 Cases subject to a budget provided to the DIP Lenders under the DIP Credit Agreement, (iii) pay for certain transaction costs, fees and expenses, and (iv) pay for certain other costs and expenses of administering the Chapter 11 Cases. We used approximately $104.0 million of the proceeds provided through the DIP Facilities to repay all obligations outstanding under the EXCO Resources Credit Agreement. Under the DIP Credit Agreement, approximately $24.0 million of outstanding letters of credit were deemed issued under the Revolver A Facility, and approximately $21.6 million of loans outstanding under the EXCO Resources Agreement were deemed exchanged for loans under the Revolver B Facility. On February 22, 2018, the Court entered into a final order authorizing entry into the DIP Credit Agreement on a final basis. The entry into the final order resulted in the termination of the EXCO Resources Credit Agreement. As of March 31, 2018 , we had $156.4 million in outstanding indebtedness and $12.0 million of letters of credit outstanding under the DIP Facilities. Our available borrowing capacity under the DIP Facilities was $81.6 million as of March 31, 2018 . All amounts outstanding under the DIP Facilities bear interest at an adjusted LIBOR plus 4.00% per annum. During the continuance of an event of default under the DIP Facilities, the outstanding amounts 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 of reorganization in the Chapter 11 Cases, or (c) the date of termination of all revolving commitments and/or the acceleration of the obligations under the DIP Facilities 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 18 months from the initial borrowing date. Borrowings under the DIP Credit Agreement are subject to an initial borrowing base of $250.0 million . Beginning on January 1, 2019, the borrowing base will be subject to adjustment semi-annually, on April 1 and October 1 of each year based upon the value of our oil and gas reserves. The DIP Lenders have considerable discretion in setting our borrowing base as part of the redetermination process. However, we may elect to redetermine the borrowing base to an amount equal to two-thirds of the net present value, discounted at nine percent, of our proved developed reserves. The DIP Lenders and the DIP Agent, subject to the Carve-Out (as defined below), at all times: (i) are entitled to joint and 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) have a 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 obligations under the 1.5 Lien Notes, 1.75 Lien Term Loans and Second Lien Term Loans, and (iv) have a first priority pledge of 100% 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-priority claims are subject in each case to a carve out (“Carve-Out”) that accounts for certain administrative, court and legal fees payable in connection with the Chapter 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 $20.0 million ; and • aggregate disbursements cannot exceed 120% of the aggregate disbursements (excluding professional fees incurred in the Chapter 11 Cases) set forth in the 13-week forecasts provided to the DIP Agent. The testing period is based on the immediately preceding 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 be consistent in all material respects with the applicable period covered by the 2018 budget that was previously delivered to the DIP Agent. As of March 31, 2018, we were in compliance with all of the covenants under 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 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 Court hearing no later than July 1, 2018 to consider the sale of all or substantially all of our assets; however, the final order entered by the Court deemed this requirement to be no longer in force and effect.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Fair value measurements	Fair value measurements We value our derivatives and other financial instruments according to FASB ASC 820, Fair Value Measurements and Disclosures , which defines 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 advantageous market 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 are not active or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractual term, 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 by management. During the three months ended March 31, 2018 and 2017 there were no changes in the fair value level classifications. Fair value of derivative financial instruments The following table presents a summary of the estimated fair value of our derivative financial instruments as of March 31, 2018 and December 31, 2017 . As of March 31, 2018 (in thousands) Level 1 Level 2 Level 3 Total Liabilities: Derivative financial instruments - common share warrants — 1,767 — 1,767 As of December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Total Assets: Derivative financial instruments - commodity derivatives $ — $ 1,150 $ — $ 1,150 Liabilities: Derivative financial instruments - common share warrants — 1,950 — 1,950 Derivative financial instruments - commodity derivatives We have historically evaluated commodity derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them on a gross basis in our Condensed Consolidated Balance Sheets. Net commodity derivative asset values are determined primarily by quoted NYMEX futures prices, notional volumes and utilization of the counterparties’ credit-adjusted risk-free rate curves and net commodity derivative liabilities are determined by utilization of our credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates of our counterparties are based on an independent market-quoted credit default swap rate curve for the counterparties’ debt plus the 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 credit default 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 fair value of our commodity derivative financial instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers or sellers. Derivative financial instruments - common share warrants The liability attributable to our common share warrants as of the issuance date and the end of each reporting period is 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 volatility were determined based on historical prices of our common shares over a period consistent with the expected remaining life. Common share warrants are measured at fair value on a recurring basis until the date of exercise or the date of expiration. See further details on our derivative financial instruments in “ Note 7. Derivative financial instruments ”. Fair value of other financial instruments Our financial instruments include cash and cash equivalents, accounts receivable and payable and accrued liabilities. The carrying amount of these instruments approximates fair value because of their short-term nature. The carrying values of our borrowings under the DIP Credit Agreement approximate fair value, as these are subject 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 have been calculated based on quoted prices in active markets. The estimated fair value of the 1.5 Lien Notes was calculated based on a model internally prepared by management that lacks significant observable inputs and was classified as Level 3. The 1.75 Lien Term Loans and the Second Lien Term Loans have 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 and 1.75 Lien Term Loans. See “ Note 8. Debt ” for the carrying value and the principal balance of each debt instrument included in the table below. As of March 31, 2018 (in thousands) Level 1 Level 2 Level 3 Total 1.5 Lien Notes $ — $ — $ 248,128 $ 248,128 1.75 Lien Term Loans — — 311,927 311,927 Second Lien Term Loans — — 7,588 7,588 2018 Notes 13,198 — — 13,198 2022 Notes 7,135 — — 7,135 As of December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Total 1.5 Lien Notes $ — $ — $ 232,276 $ 232,276 1.75 Lien Term Loans — — 372,186 372,186 Second Lien Term Loans — — 9,054 9,054 2018 Notes 4,658 — — 4,658 2022 Notes 2,586 — — 2,586

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Income taxes	Income taxes We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our annual effective tax rate is highly sensitive to estimates of ordinary income or loss primarily due to significant permanent differences related to the non-taxable gains or losses on the 2017 Warrants and non-deductible interest on our 1.5 Lien Notes and 1.75 Lien Term Loans. We have accumulated financial net deferred tax assets primarily due to losses arising from impairments to the carrying value of our oil and natural gas properties that are subject to valuation allowances. Our valuation allowances increased $43.3 million for the three months ended March 31, 2018 . As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $886.8 million that have fully offset our net deferred tax assets as of March 31, 2018 . The valuation allowances will continue to be recognized until the realization of future deferred tax benefits are more likely than not to become utilized. The valuation allowances do not impact future utilization of the underlying tax attributes. The utilization of our net operating loss carryforwards (“NOLs”) to offset taxable income in future periods may be limited if we undergo an ownership change pursuant to the criteria in Section 382 of the Internal Revenue Code. Generally, an ownership change occurs for Section 382 purposes when the percentage of stock held by one or more five -percent shareholders increases by more than 50 percentage points over the lowest stock ownership held by such shareholders on any testing date within a three -year period. See further discussion of restrictions imposed by the Court on the trading of our equity securities to protect our use of NOLs in “ Note 1. Organization and basis of presentation ”. 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 this occurs, 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 offset cancellation of debt income in a Chapter 11 case are not limited by Section 382 of the Internal Revenue Code. As of March 31, 2018, we had estimated NOLs of $2.1 billion . On December 22, 2017, the United States enacted the Tax Act which, among other things, lowered the U.S. Federal tax rate from 35% to 21% , repealed the corporate alternative minimum tax, and provided for a refund of previously accrued alternative minimum tax credits. We reflected 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 the law is enacted. The Tax Act also repealed the corporate alternative minimum tax for tax years beginning after January 1, 2018 and provided that prior alternative 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 and monetization opportunities under current law in 2017. In addition, the Tax Act limits the amount taxpayers are able to deduct for NOLs generated in taxable years beginning after December 31, 2017 to 80% of the taxpayer’s taxable income. The law also generally repeals all carrybacks for losses generated in taxable years ending after December 31, 2017. However, any NOLs generated in taxable years ending after December 31, 2017 can be carried forward indefinitely. We are still analyzing certain aspects of the Tax Act, which could potentially affect 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 estimates provided herein, possibly materially, due to additional regulatory guidance, changes in interpretations and assumptions, and other actions as a result of the Tax Act. As of December 31, 2017, we recognized a deferred tax liability of $4.5 million for tax-deductible goodwill. The deferred tax liability related to goodwill was considered to have an indefinite life based on the nature of the underlying asset and could not be offset under GAAP with a deferred tax asset with a definite life, such as NOLs. As a result of the Tax Act, deferred tax assets resulting from NOLs generated in taxable years subsequent to December 31, 2017 are considered to have an indefinite life. Therefore, we recognized an income tax benefit of $4.5 million during the three months ended March 31, 2018 because we expect to be able to utilize deferred tax assets related to NOLs to offset the deferred tax liability related to goodwill.

Condensed Consolidating Financi

Condensed Consolidating Financial Statements	3 Months Ended
	Mar. 31, 2018
Condensed Financial Statements, Captions [Line Items]
Condensed consolidating financial statements	Condensed consolidating financial statements As of March 31, 2018 , the majority of EXCO’s subsidiaries were guarantors under the DIP Credit Agreement, the indenture governing the 1.5 Lien Notes, the credit agreements governing the 1.75 Lien Term Loans and Second Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes. All of our unrestricted subsidiaries under the 1.5 Lien Notes, 1.75 Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes are considered non-guarantor subsidiaries. Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The DIP Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes, which were issued by EXCO Resources, Inc., are jointly and severally guaranteed by substantially all of our subsidiaries (referred to as Guarantor Subsidiaries). For purposes of this footnote, EXCO Resources, Inc. is referred to as Resources to distinguish it from the Guarantor Subsidiaries. Each of the Guarantor Subsidiaries is a 100% owned subsidiary of Resources and the guarantees are unconditional as they relate to the assets of the Guarantor Subsidiaries. Resources and the Guarantor Subsidiaries solely consist of entities that are Debtors in the Chapter 11 Cases, including each of the Filing Subsidiaries. The non-guarantor subsidiaries solely consist of entities that are not included in the Chapter 11 Cases, including OPCO, Appalachia Midstream, EXCO Production Company (PA) II, LLC, EXCO Production Company (WV) II, LLC and certain other entities (referred to as Non-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 information for the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries is presented on a combined basis. The elimination entries primarily eliminate investments in subsidiaries and intercompany balances and transactions. EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited) As of March 31, 2018 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 61,889 $ (11,791 ) $ 15,732 $ — $ 65,830 Restricted cash 552 9,280 — — 9,832 Other current assets 11,056 110,931 7,720 — 129,707 Total current assets 73,497 108,420 23,452 — 205,369 Equity investments — — 4,736 — 4,736 Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties and development costs not being amortized — 115,780 33,542 — 149,322 Proved developed and undeveloped oil and natural gas properties 334,199 2,832,863 72,556 — 3,239,618 Accumulated depletion (330,776 ) (2,438,901 ) (601 ) — (2,770,278 ) Oil and natural gas properties, net 3,423 509,742 105,497 — 618,662 Other property and equipment, net and other non-current assets 1,013 20,285 18,047 — 39,345 Investments in and (advances to) affiliates, net 306,795 — — (306,795 ) — Goodwill 13,293 149,862 — — 163,155 Total assets $ 398,021 $ 788,309 $ 151,732 $ (306,795 ) $ 1,031,267 Liabilities and shareholders’ equity Current maturities of long-term debt $ 473,364 $ — $ — $ — $ 473,364 Other current liabilities 15,452 71,055 7,325 — 93,832 Other long-term liabilities — 11,631 12,222 — 23,853 Liabilities subject to compromise 965,858 531,013 — — 1,496,871 Payable to parent — 2,458,854 (1,518 ) (2,457,336 ) — Total shareholders’ equity (1,056,653 ) (2,284,244 ) 133,703 2,150,541 (1,056,653 ) Total liabilities and shareholders’ equity $ 398,021 $ 788,309 $ 151,732 $ (306,795 ) $ 1,031,267 EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING BALANCE SHEET As of December 31, 2017 (in thousands) Resources Guarantor Non-Guarantor Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 49,170 $ (9,573 ) $ — $ — $ 39,597 Restricted cash — 15,271 — — 15,271 Other current assets 22,697 90,265 — — 112,962 Total current assets 71,867 95,963 — — 167,830 Equity investments — — 14,181 — 14,181 Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties and development costs not being amortized — 118,652 — — 118,652 Proved developed and undeveloped oil and natural gas properties 333,719 2,773,847 — — 3,107,566 Accumulated depletion (330,777 ) (2,421,534 ) — — (2,752,311 ) Oil and natural gas properties, net 2,942 470,965 — — 473,907 Other property and equipment, net and other non-current assets 892 20,382 — — 21,274 Investments in and (advances to) affiliates, net 466,055 — — (466,055 ) — Goodwill 13,293 149,862 — — 163,155 Total assets $ 555,049 $ 737,172 $ 14,181 $ (466,055 ) $ 840,347 Liabilities and shareholders’ equity Current maturities of long-term debt $ 1,362,500 $ — $ — $ — $ 1,362,500 Other current liabilities 32,280 272,190 — — 304,470 Derivative financial instruments - common share warrants 1,950 — — — 1,950 Other long-term liabilities 4,518 13,108 — — 17,626 Payable 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 ) $ 840,347 EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited) For the Three Months Ended March 31, 2018 (in thousands) Resources Guarantor Non-Guarantor Eliminations Consolidated Revenues: Oil and natural gas $ — $ 83,296 $ 1,850 $ — $ 85,146 Purchased natural gas and marketing — 5,318 — — 5,318 Total revenues — 88,614 1,850 — 90,464 Costs and expenses: Oil and natural gas production — 11,447 457 — 11,904 Gathering and transportation — 19,651 325 — 19,976 Purchased natural gas — 4,115 — — 4,115 Depletion, depreciation and amortization 80 17,463 663 — 18,206 Accretion of liabilities — 229 113 — 342 General and administrative (6,780 ) 14,872 435 — 8,527 Gain on Appalachia JV Settlement — — (119,477 ) — (119,477 ) Other operating items (34 ) 9,800 (9,632 ) — 134 Total costs and expenses (6,734 ) 77,577 (127,116 ) — (56,273 ) Operating income 6,734 11,037 128,966 — 146,737 Other expense: Interest expense, net (9,173 ) — — — (9,173 ) Loss on derivative financial instruments - commodity derivatives (615 ) — — — (615 ) Gain on derivative financial instruments - common share warrants 183 — — — 183 Other income 17 5 — — 22 Equity income — 179 — — 179 Reorganization items, net (43,703 ) (309,197 ) — — (352,900 ) Net loss from consolidated subsidiaries (169,010 ) — — 169,010 — Total other expense (222,301 ) (309,013 ) — 169,010 (362,304 ) Income (loss) before income taxes (215,567 ) (297,976 ) 128,966 169,010 (215,567 ) Income tax benefit (4,518 ) — — — (4,518 ) Net income (loss) $ (211,049 ) $ (297,976 ) $ 128,966 $ 169,010 $ (211,049 ) EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited) For the Three Months Ended March 31, 2017 (in thousands) Resources Guarantor Non-Guarantor Eliminations Consolidated Revenues: Oil and natural gas $ — $ 69,356 $ — $ — $ 69,356 Purchased natural gas and marketing — 7,173 — — 7,173 Total revenues — 76,529 — — 76,529 Costs and expenses: Oil and natural gas production — 11,933 — — 11,933 Gathering and transportation — 27,353 — — 27,353 Purchased natural gas — 6,452 — — 6,452 Depletion, depreciation and amortization 61 11,447 — — 11,508 Accretion of liabilities — 212 — — 212 General and administrative (10,667 ) 15,082 — — 4,415 Other operating items 398 671 — — 1,069 Total costs and expenses (10,208 ) 73,150 — — 62,942 Operating income 10,208 3,379 — — 13,587 Other income (expense): Interest expense, net (19,952 ) — — — (19,952 ) Gain on derivative financial instruments - commodity derivatives 15,533 — — — 15,533 Gain on derivative financial instruments - common share warrants 6,004 — — — 6,004 Loss on restructuring of debt (6,272 ) — — — (6,272 ) Other income 1 3 — — 4 Equity income — — 317 — 317 Net income from consolidated subsidiaries 3,699 — — (3,699 ) — Total other income (expense) (987 ) 3 317 (3,699 ) (4,366 ) Income before income taxes 9,221 3,382 317 (3,699 ) 9,221 Income tax expense 1,028 — — — 1,028 Net income $ 8,193 $ 3,382 $ 317 $ (3,699 ) $ 8,193 EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited) For the Three Months Ended March 31, 2018 (in thousands) Resources Guarantor Non-Guarantor Eliminations Consolidated Operating Activities: Net cash provided by (used in) operating activities $ (10,768 ) $ 58,120 $ 900 $ — $ 48,252 Investing Activities: Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions (527 ) (66,329 ) 14,832 — (52,024 ) Net cash provided by (used in) investing activities (527 ) (66,329 ) 14,832 — (52,024 ) Financing Activities: Borrowings under DIP Credit Agreement 156,406 — — — 156,406 Repayments under EXCO Resources Credit Agreement (126,401 ) — — — (126,401 ) Debt financing costs and other (5,439 ) — — — (5,439 ) Net cash provided by financing activities 24,566 — — — 24,566 Net increase (decrea se) in cash, cash equivalents and restricted cash 13,271 (8,209 ) 15,732 — 20,794 Cash, cash equivalents and restricted cash at beginning of period 49,170 5,698 — — 54,868 Cash, cash equivalents and restricted cash at end of period $ 62,441 $ (2,511 ) $ 15,732 $ — $ 75,662 EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited) For the Three Months Ended March 31, 2017 (in thousands) Resources Guarantor Non-Guarantor Eliminations Consolidated Operating Activities: Net cash provided by (used in) operating activities $ (12,106 ) $ 17,302 $ — $ — $ 5,196 Investing Activities: Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions (271 ) (11,586 ) — — (11,857 ) Net changes in amounts due to joint ventures — (3,723 ) — — (3,723 ) Advances/investments with affiliates (6,998 ) 6,998 — — — Net cash used in investing activities (7,269 ) (8,311 ) — — (15,580 ) Financing Activities: Borrowings under EXCO Resources Credit Agreement 25,000 — — — 25,000 Repayments under EXCO Resources Credit Agreement (253,592 ) — — — (253,592 ) Proceeds received from issuance of 1.5 Lien Notes, net 295,530 — — — 295,530 Payments on Second Lien Term Loans (10,512 ) — — — (10,512 ) Debt financing costs and other (18,636 ) — — — (18,636 ) Net cash provided by financing activities 37,790 — — — 37,790 Net increase in cash , cash equivalents and restricted cash 18,415 8,991 — — 27,406 Cash, cash equivalents and restricted cash at beginning of period 24,610 (4,392 ) — — 20,218 Cash, cash equivalents and restricted cash at end of period $ 43,025 $ 4,599 $ — $ — $ 47,624

Summary Of Significant Accoun18

Summary Of Significant Accounting Policies (Policy)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Industry Specific Policies, Oil and Gas [Policy Text Block]	We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties (“collectively, the “full cost pool”). 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 to proved properties as a result of extensions or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. The majority of our undeveloped properties are held-by-production, which reduces the risk of impairment as a result of lease expirations. There were no impairments of unproved properties during the three months ended March 31, 2018 or 2017 . At the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs (“ceiling test”). The ceiling test involves comparing the net book value of the full cost 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 are required to record an impairment of our oil and natural gas properties. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our proved reserves by applying the average price as prescribed by the SEC, less estimated future expenditures (based on current costs) to develop and produce the proved reserves, discounted at 10% , plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects. During March 2018, the Court approved the rejection of certain executory contracts related to the sale, marketing and transportation of natural gas in the North Louisiana region. The rejection of these executory contracts has positively impacted the present value of our proved reserves. See further discussion of the rejection of executory contracts in “Note 1. Organization and basis of presentation”. The ceiling test for each period was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing twelve-month simple average spot prices at the first of the month for natural gas at Henry Hub (“HH”) and West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in oil and natural gas prices between each of the periods and have a significant impact on our ceiling test limitation. The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are inherent uncertainties in estimating quantities of proved reserves including projecting the future rates of production and the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data, and engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.
New Accounting Pronouncements	Recent accounting pronouncements In February 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842) (“ASU 2016-02”). The main difference between the current requirement under GAAP and ASU 2016-02 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating 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). The liability 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. For income statement purposes, the FASB retained a dual model, requiring leases to be classified as either operating or finance leases. Operating leases will result in straight-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 the classification criteria and the accounting for sales-type and direct financing leases. ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and early adoption is permitted. ASU 2016-02 must be adopted using a modified retrospective transition, and provides for certain practical expedients. These transactions will require application of the new guidance at the beginning of the earliest comparative period presented. In January 2018, the FASB issued further guidance on the new lease standard in ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). ASU 2018-01 provides a practical expedient to exclude existing or expired land easements from the evaluation of leases under ASU 2016-02 if the easements were not previously accounted for as leases under the current guidance. We are currently assessing the potential impact of ASU 2016-02 and related clarifying updates and expect they will have an impact on our consolidated financial condition and results of operations upon adoption. We are currently unable to quantify the impact the standard will have 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 Emerging Issues 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 cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. ASU 2016-18 is effective for annual and interim periods beginning after December 15, 2017 and early adoption is permitted. We adopted ASU 2016-18 in the first quarter of 2018 utilizing retrospective application. The adoption resulted in an increase in reported investing cash flows of $4.4 million for the three months ended March 31, 2017 with a corresponding adjustment to the reported end of period cash balances. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017. Under ASU 2017-01, an entity must 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 similar assets. 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 a business includes, at a minimum, an input and a substantive process that together significantly contribute to the ability to create outputs. ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017. We adopted ASU 2017-01 in the first quarter of 2018 and will apply the guidance of ASU 2017-01 prospectively to future asset acquisitions, including the acquisitions as part of the Appalachia JV Settlement during the first quarter of 2018. In July 2017, the FASB issued ASU No. 2017-11, Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), Derivatives and Hedging (Topic 815): I. Accounting for Certain Financial Instruments with Down Round Features, II. Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception (“ASU 2017-11”). ASU 2017-11 revises the guidance for instruments with down round features in Subtopic 815-40, Derivatives and Hedging - Contracts in Entity’s Own Equity , which is considered in determining whether an equity-linked financial instrument qualifies for a scope exception from derivative accounting. An entity is still required to determine whether instruments would be classified in equity under the guidance in Subtopic 815-40 in determining whether they qualify for that scope exception. If they do qualify, freestanding instruments with down round features are no longer classified as liabilities. Our 2017 Warrants (as defined in “Note 7. Derivative financial instruments”) are required to be classified as liabilities under the current guidance due to their down round features. The amendments in Part I are required to be applied retrospectively to outstanding financial instruments with down round features. ASU 2017-11 is effective for annual and interim periods beginning after December 15, 2018, and early adoption is permitted, including adoption in an interim period. We are currently assessing the impact of ASU 2017-11; however, we believe that it could have an impact on our consolidated financial condition and results of operations if we determine the 2017 Warrants qualify for equity classification. However, we believe it is highly likely that our existing common shares as well as the 2017 Warrants will be canceled at the conclusion of our Chapter 11 Cases. In March 2018, the FASB issued ASU No. 2018-05, Income Taxes (Topic 740): Amendments to SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 118 (“ASU 2018-05”). The Amendments in this update add various SEC paragraphs pursuant to the issuance of SEC Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”). SAB 118 directs taxpayers to consider the implications of the Tax Cuts and Jobs Act (“Tax Act”) as provisional when it does not have the necessary information available, prepared, or analyzed in reasonable detail to complete its accounting for the change in the tax law. SAB 118 provides a one-year measurement period from a registrant’s reporting period that includes the Tax Act’s enactment date to allow the registrant sufficient time to obtain, prepare and analyze information to complete the required accounting under ASC 740. As described in the 2017 Form 10-K, we reflected the impact of the changes in rates on our deferred tax assets and liabilities at December 31, 2017, as we are required to reflect the change in the period in which the law is enacted. We are still analyzing certain aspects of the Tax Act, which could potentially affect 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 estimates provided herein, possibly materially, due to additional regulatory guidance, changes in interpretations and assumptions, and other actions as a result of the Tax Act. 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 the International Accounting Standards Board jointly issued this comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under GAAP. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised 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 or services. The FASB issued additional ASUs that primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectability, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017 and permits the use of either the retrospective or cumulative effect transition method. We adopted ASU 2014-09 and related updates in the first quarter of 2018 based on the modified retrospective method of adoption. The adoption of this standard did not have an impact on our consolidated financial condition and results of operations. We have implemented processes to ensure new contracts are reviewed for the appropriate accounting treatment and to generate the disclosures required under the new standard. Overview of marketing arrangements 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 under contracts using market sensitive pricing. The majority of our oil contracts are based on NYMEX pricing, which is typically calculated as the average of the daily closing prices of oil to be delivered one month in the future. We also 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 a type common within the industry, and we usually negotiate a separate contract for each area. Generally, we sell our oil to purchasers and refiners near the areas 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 in length from spot market sales of a single day to term agreements that may extend for a month or more. Our natural gas customers primarily include natural gas marketing companies. The natural gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market varies daily, reflecting changing market conditions. Revenue recognition under ASC 606 We use the sales method of accounting for oil and natural gas revenues. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes primarily on company-measured volume readings. We then adjust 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 March 31, 2018 and December 31, 2017 were not significant. We generally sell oil and natural gas under two types of agreements that are common in our industry. Both types of agreements include transportation charges. We evaluate whether we are the principal or the agent in each transaction. The first type of agreement is a net-back arrangement, under which we sell oil or natural gas at the wellhead and collect a price, net of the transportation costs incurred by the purchaser. The purchaser takes custody, title and risk of loss of the oil or natural gas at the wellhead. In this case, we record revenue when the control transfers to the purchaser at the wellhead based on the price received, net of the transportation costs. Under the second type of agreement, 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 transportation deduction. The purchaser takes custody, title, and risk of loss of the oil or natural gas at the specific delivery point. In this case, we are deemed to be the principal and the ultimate third-party purchaser is deemed to be the customer. We recognize revenue when control transfers to the purchaser at the specific delivery point based on the price received from the purchaser. The costs that we incur to transport the oil or natural gas are recorded as gathering and transportation expenses. As such, our computed realized prices include revenues that are recognized under two separate bases. Raider Marketing, LP (“Raider”) is a wholly owned subsidiary focused on the marketing of oil and natural gas. Raider purchases and resells natural gas from third-party producers, as well as oil and natural gas from operated wells in Texas and Louisiana, and charges a fee for marketing services to certain working interest owners in the related wells. Raider takes custody, title and risk of loss from the third-party producer upon the purchase of natural gas, then sells the natural gas to a separate third-party purchaser further downstream. The price paid for the purchase of natural gas from the third-party producer is not dependent on the price received from the ultimate purchaser. We are deemed to be the principal in these transactions. As such, third party purchases and sales are reported on a gross basis as “Purchased natural gas” expenses and “Purchased natural gas and marketing” revenues, respectively. The marketing fee charged by Raider to certain working interest owners in our operated wells is reported as “Purchased natural gas and marketing” revenues. Transaction price allocated to remaining performance obligations Our sales are short-term in nature with a contract term of one year or less. We have utilized the practical expedient in ASC 606-10-50-14 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Contract balances Under our oil and natural gas sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our oil and natural gas sales contracts do not give rise to contract assets or liabilities under ASC 606. Prior-period performance obligations We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil and natural gas sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three months ended March 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Organization And Basis Of Pre19

Organization And Basis Of Presentation Organization and Basis of Presentation (Tables)	3 Months Ended
	Mar. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Liabilities Subject to Compromise	The following table summarizes the components of liabilities subject to compromise included on the Condensed Consolidated Balance Sheet as of March 31, 2018: (in thousands) March 31, 2018 Current maturities of long-term debt $ 927,917 Accrued interest payable 34,281 Accounts payable, accrued expenses and other liabilities 118,710 Liabilities related to rejected executory contracts 415,963 Liabilities subject to compromise $ 1,496,871
Schedule of Reorganization Items	The following table summarizes the components included in “Reorganization items, net” in our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018: (in thousands) Three Months Ended March 31, 2018 Legal and professional fees $ 13,850 Deferred financing costs, debt discounts and deferred reductions in carrying value 29,853 Rejection of executory contracts 309,197 Reorganization items, net $ 352,900

Acquisitions, Divestitures an20

Acquisitions, Divestitures and Other Significant Events (Tables)	3 Months Ended
	Mar. 31, 2018
Business Combinations [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table presents a summary of the fair value of assets acquired and liabilities assumed as part of the Appalachia JV Settlement as of the closing date. (in thousands) Amount Assets acquired: Cash and cash equivalents $ 14,832 Accounts receivable, net 6,493 Other current assets 5,264 Unproved oil and natural gas properties 33,542 Proved developed and undeveloped oil and natural gas properties, net 72,548 Other assets 18,109 Liabilities assumed: Accounts payable and accrued liabilities (9,478 ) Asset retirement obligations (2,315 ) Other long-term liabilities (9,895 ) Fair value of net assets acquired $ 129,100
Business Acquisition, Pro Forma Information	Pro forma results of operations - The following table reflects the unaudited pro forma results of operations if the Appalachia JV Settlement had occurred on January 1, 2017: Three Months Ended March 31, (in thousands except for per share data) 2018 2017 Oil and natural gas revenues $ 94,543 $ 83,557 Net income (loss) (209,789 ) 10,159 Basic earnings (loss) per share $ (9.58 ) $ 0.54 Diluted earnings (loss) per share $ (9.58 ) $ 0.54

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2018
Asset Retirement Obligation [Abstract]
Schedule of Asset Retirement Obligations	The following is a reconciliation of our asset retirement obligations for the three months ended March 31, 2018 : (in thousands) Asset retirement obligations at beginning of period $ 12,017 Activity during the period: Liabilities incurred during the period — Revisions in estimated assumptions (1 ) Liabilities settled during the period (7 ) Adjustment to liability due to acquisitions (1) 2,315 Adjustment to liability due to divestitures (7 ) Accretion of discount 241 Asset retirement obligations at end of period 14,558 Less current portion 600 Long-term portion $ 13,958 (1) The increase in our asset retirement obligations during the three months ended March 31, 2018 is primarily due to additional interests in oil and natural gas properties acquired as part of the Appalachia JV Settlement.

Oil and Natural Gas Properties

Oil and Natural Gas Properties Oil and Natural Gas Properties (Tables)	3 Months Ended
	Mar. 31, 2018
Oil and Gas Property [Abstract]
Average spot prices	Average spot prices Oil (per Bbl) Natural gas (per Mmbtu) March 31, 2018 $ 53.49 $ 3.00 December 31, 2017 51.34 2.98

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Basic And Diluted Earnings Per Share Computations	The following table presents the basic and diluted earnings (loss) per share computations, adjusted to give effect to our reverse share split, for the three months ended March 31, 2018 and 2017 : Three Months Ended March 31, (in thousands, except per share data) 2018 2017 Basic net income (loss) per common share: Net income (loss) $ (211,049 ) $ 8,193 Weighted average common shares outstanding 21,902 18,726 Net income (loss) per basic common share $ (9.64 ) $ 0.44 Diluted net income (loss) per common share: Net income (loss) $ (211,049 ) $ 8,193 Weighted average common shares outstanding 21,902 18,726 Dilutive effect of: Restricted shares and restricted share units — 23 Weighted average common shares and common share equivalents outstanding 21,902 18,749 Net income (loss) per diluted common share $ (9.64 ) $ 0.44

Derivative Financial Instrume24

Derivative Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2018
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Fair Value Of Derivative Financial Instruments	The table below presents the effect of derivative financial instruments on our Condensed Consolidated Balance Sheets: (in thousands) March 31, 2018 December 31, 2017 Current assets Derivative financial instruments - commodity derivatives $ — $ 1,150 Liabilities subject to compromise Derivative financial instruments - common share warrants $ (1,767 ) $ — Long-term liabilities Derivative financial instruments - common share warrants — (1,950 )
Gain (Loss) of Derivative Financial Instruments in Statement of Financial Performance	The table below presents the effect of derivative financial instruments on our Condensed Consolidated Statements of Operations. Three Months Ended March 31, (in thousands) 2018 2017 Gain (loss) on derivative financial instruments - commodity derivatives $ (615 ) $ 15,533 Gain on derivative financial instruments - common share warrants 183 6,004

Debt (Tables)

Debt (Tables)	3 Months Ended
	Mar. 31, 2018
Long-term Debt, Current and Noncurrent [Abstract]
Schedule Of Debt	The carrying value of our total debt is summarized as follows: (in thousands) March 31, 2018 December 31, 2017 DIP Credit Agreement $ 156,406 $ — EXCO Resources Credit Agreement — 126,401 1.5 Lien Notes, net of unamortized discount 316,958 176,560 1.75 Lien Term Loans, net of unamortized discount 708,926 845,763 Second Lien Term Loans 17,246 23,543 2018 Notes, net of unamortized discount 131,576 131,345 2022 Notes 70,169 70,169 Deferred financing costs, net — (11,281 ) Total debt, net 1,401,281 1,362,500 Less amounts included in liabilities subject to compromise 927,917 — Current maturities of long-term debt $ 473,364 $ 1,362,500

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Summary Of Estimated Fair Value Of Derivative Financial Instruments	The following table presents a summary of the estimated fair value of our derivative financial instruments as of March 31, 2018 and December 31, 2017 . As of March 31, 2018 (in thousands) Level 1 Level 2 Level 3 Total Liabilities: Derivative financial instruments - common share warrants — 1,767 — 1,767 As of December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Total Assets: Derivative financial instruments - commodity derivatives $ — $ 1,150 $ — $ 1,150 Liabilities: Derivative financial instruments - common share warrants — 1,950 — 1,950
Schedule Of Estimated Fair Value Of Other Financial Instruments	As of March 31, 2018 (in thousands) Level 1 Level 2 Level 3 Total 1.5 Lien Notes $ — $ — $ 248,128 $ 248,128 1.75 Lien Term Loans — — 311,927 311,927 Second Lien Term Loans — — 7,588 7,588 2018 Notes 13,198 — — 13,198 2022 Notes 7,135 — — 7,135 As of December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Total 1.5 Lien Notes $ — $ — $ 232,276 $ 232,276 1.75 Lien Term Loans — — 372,186 372,186 Second Lien Term Loans — — 9,054 9,054 2018 Notes 4,658 — — 4,658 2022 Notes 2,586 — — 2,586

Condensed Consolidating Finan27

Condensed Consolidating Financial Statements (Tables)	3 Months Ended
	Mar. 31, 2018
Condensed Financial Statements, Captions [Line Items]
Schedule Of Condensed Consolidating Balance Sheet	EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING BALANCE SHEET (Unaudited) As of March 31, 2018 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 61,889 $ (11,791 ) $ 15,732 $ — $ 65,830 Restricted cash 552 9,280 — — 9,832 Other current assets 11,056 110,931 7,720 — 129,707 Total current assets 73,497 108,420 23,452 — 205,369 Equity investments — — 4,736 — 4,736 Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties and development costs not being amortized — 115,780 33,542 — 149,322 Proved developed and undeveloped oil and natural gas properties 334,199 2,832,863 72,556 — 3,239,618 Accumulated depletion (330,776 ) (2,438,901 ) (601 ) — (2,770,278 ) Oil and natural gas properties, net 3,423 509,742 105,497 — 618,662 Other property and equipment, net and other non-current assets 1,013 20,285 18,047 — 39,345 Investments in and (advances to) affiliates, net 306,795 — — (306,795 ) — Goodwill 13,293 149,862 — — 163,155 Total assets $ 398,021 $ 788,309 $ 151,732 $ (306,795 ) $ 1,031,267 Liabilities and shareholders’ equity Current maturities of long-term debt $ 473,364 $ — $ — $ — $ 473,364 Other current liabilities 15,452 71,055 7,325 — 93,832 Other long-term liabilities — 11,631 12,222 — 23,853 Liabilities subject to compromise 965,858 531,013 — — 1,496,871 Payable to parent — 2,458,854 (1,518 ) (2,457,336 ) — Total shareholders’ equity (1,056,653 ) (2,284,244 ) 133,703 2,150,541 (1,056,653 ) Total liabilities and shareholders’ equity $ 398,021 $ 788,309 $ 151,732 $ (306,795 ) $ 1,031,267 EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING BALANCE SHEET As of December 31, 2017 (in thousands) Resources Guarantor Non-Guarantor Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 49,170 $ (9,573 ) $ — $ — $ 39,597 Restricted cash — 15,271 — — 15,271 Other current assets 22,697 90,265 — — 112,962 Total current assets 71,867 95,963 — — 167,830 Equity investments — — 14,181 — 14,181 Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties and development costs not being amortized — 118,652 — — 118,652 Proved developed and undeveloped oil and natural gas properties 333,719 2,773,847 — — 3,107,566 Accumulated depletion (330,777 ) (2,421,534 ) — — (2,752,311 ) Oil and natural gas properties, net 2,942 470,965 — — 473,907 Other property and equipment, net and other non-current assets 892 20,382 — — 21,274 Investments in and (advances to) affiliates, net 466,055 — — (466,055 ) — Goodwill 13,293 149,862 — — 163,155 Total assets $ 555,049 $ 737,172 $ 14,181 $ (466,055 ) $ 840,347 Liabilities and shareholders’ equity Current maturities of long-term debt $ 1,362,500 $ — $ — $ — $ 1,362,500 Other current liabilities 32,280 272,190 — — 304,470 Derivative financial instruments - common share warrants 1,950 — — — 1,950 Other long-term liabilities 4,518 13,108 — — 17,626 Payable 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 ) $ 840,347
Schedule Of Condensed Consolidating Statement Of Operations	EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited) For the Three Months Ended March 31, 2018 (in thousands) Resources Guarantor Non-Guarantor Eliminations Consolidated Revenues: Oil and natural gas $ — $ 83,296 $ 1,850 $ — $ 85,146 Purchased natural gas and marketing — 5,318 — — 5,318 Total revenues — 88,614 1,850 — 90,464 Costs and expenses: Oil and natural gas production — 11,447 457 — 11,904 Gathering and transportation — 19,651 325 — 19,976 Purchased natural gas — 4,115 — — 4,115 Depletion, depreciation and amortization 80 17,463 663 — 18,206 Accretion of liabilities — 229 113 — 342 General and administrative (6,780 ) 14,872 435 — 8,527 Gain on Appalachia JV Settlement — — (119,477 ) — (119,477 ) Other operating items (34 ) 9,800 (9,632 ) — 134 Total costs and expenses (6,734 ) 77,577 (127,116 ) — (56,273 ) Operating income 6,734 11,037 128,966 — 146,737 Other expense: Interest expense, net (9,173 ) — — — (9,173 ) Loss on derivative financial instruments - commodity derivatives (615 ) — — — (615 ) Gain on derivative financial instruments - common share warrants 183 — — — 183 Other income 17 5 — — 22 Equity income — 179 — — 179 Reorganization items, net (43,703 ) (309,197 ) — — (352,900 ) Net loss from consolidated subsidiaries (169,010 ) — — 169,010 — Total other expense (222,301 ) (309,013 ) — 169,010 (362,304 ) Income (loss) before income taxes (215,567 ) (297,976 ) 128,966 169,010 (215,567 ) Income tax benefit (4,518 ) — — — (4,518 ) Net income (loss) $ (211,049 ) $ (297,976 ) $ 128,966 $ 169,010 $ (211,049 ) EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited) For the Three Months Ended March 31, 2017 (in thousands) Resources Guarantor Non-Guarantor Eliminations Consolidated Revenues: Oil and natural gas $ — $ 69,356 $ — $ — $ 69,356 Purchased natural gas and marketing — 7,173 — — 7,173 Total revenues — 76,529 — — 76,529 Costs and expenses: Oil and natural gas production — 11,933 — — 11,933 Gathering and transportation — 27,353 — — 27,353 Purchased natural gas — 6,452 — — 6,452 Depletion, depreciation and amortization 61 11,447 — — 11,508 Accretion of liabilities — 212 — — 212 General and administrative (10,667 ) 15,082 — — 4,415 Other operating items 398 671 — — 1,069 Total costs and expenses (10,208 ) 73,150 — — 62,942 Operating income 10,208 3,379 — — 13,587 Other income (expense): Interest expense, net (19,952 ) — — — (19,952 ) Gain on derivative financial instruments - commodity derivatives 15,533 — — — 15,533 Gain on derivative financial instruments - common share warrants 6,004 — — — 6,004 Loss on restructuring of debt (6,272 ) — — — (6,272 ) Other income 1 3 — — 4 Equity income — — 317 — 317 Net income from consolidated subsidiaries 3,699 — — (3,699 ) — Total other income (expense) (987 ) 3 317 (3,699 ) (4,366 ) Income before income taxes 9,221 3,382 317 (3,699 ) 9,221 Income tax expense 1,028 — — — 1,028 Net income $ 8,193 $ 3,382 $ 317 $ (3,699 ) $ 8,193
Schedule Of Condensed Consolidating Statement Of Cash Flows	EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited) For the Three Months Ended March 31, 2018 (in thousands) Resources Guarantor Non-Guarantor Eliminations Consolidated Operating Activities: Net cash provided by (used in) operating activities $ (10,768 ) $ 58,120 $ 900 $ — $ 48,252 Investing Activities: Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions (527 ) (66,329 ) 14,832 — (52,024 ) Net cash provided by (used in) investing activities (527 ) (66,329 ) 14,832 — (52,024 ) Financing Activities: Borrowings under DIP Credit Agreement 156,406 — — — 156,406 Repayments under EXCO Resources Credit Agreement (126,401 ) — — — (126,401 ) Debt financing costs and other (5,439 ) — — — (5,439 ) Net cash provided by financing activities 24,566 — — — 24,566 Net increase (decrea se) in cash, cash equivalents and restricted cash 13,271 (8,209 ) 15,732 — 20,794 Cash, cash equivalents and restricted cash at beginning of period 49,170 5,698 — — 54,868 Cash, cash equivalents and restricted cash at end of period $ 62,441 $ (2,511 ) $ 15,732 $ — $ 75,662 EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited) For the Three Months Ended March 31, 2017 (in thousands) Resources Guarantor Non-Guarantor Eliminations Consolidated Operating Activities: Net cash provided by (used in) operating activities $ (12,106 ) $ 17,302 $ — $ — $ 5,196 Investing Activities: Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions (271 ) (11,586 ) — — (11,857 ) Net changes in amounts due to joint ventures — (3,723 ) — — (3,723 ) Advances/investments with affiliates (6,998 ) 6,998 — — — Net cash used in investing activities (7,269 ) (8,311 ) — — (15,580 ) Financing Activities: Borrowings under EXCO Resources Credit Agreement 25,000 — — — 25,000 Repayments under EXCO Resources Credit Agreement (253,592 ) — — — (253,592 ) Proceeds received from issuance of 1.5 Lien Notes, net 295,530 — — — 295,530 Payments on Second Lien Term Loans (10,512 ) — — — (10,512 ) Debt financing costs and other (18,636 ) — — — (18,636 ) Net cash provided by financing activities 37,790 — — — 37,790 Net increase in cash , cash equivalents and restricted cash 18,415 8,991 — — 27,406 Cash, cash equivalents and restricted cash at beginning of period 24,610 (4,392 ) — — 20,218 Cash, cash equivalents and restricted cash at end of period $ 43,025 $ 4,599 $ — $ — $ 47,624

Organization And Basis Of Pre28

Organization And Basis Of Presentation (Narrative) (Details)	1 Months Ended	3 Months Ended
	Mar. 31, 2018USD ($)MMBTU	Mar. 31, 2018USD ($)	Jan. 22, 2018USD ($)	Jan. 15, 2018USD ($)	Dec. 31, 2017USD ($)
Debt instrument, principal outstanding				$ 1,400,000,000
Revolving Credit Facility | EXCO Resources Credit Agreement
Debt instrument, principal outstanding				126,400,000
Secured Debt | 1.5 Lien Notes
Debt instrument, principal outstanding				317,000,000
Secured Debt | 1.75 Lien Notes
Debt instrument, principal outstanding				708,900,000
Secured Debt | Second Lien Term Loan
Debt instrument, principal outstanding				17,200,000
Secured Debt | Revolving Credit Facility
Debtor-in-Possession Financing, Amount Arranged			$ 250,000,000
Debtor-in-Possession Financing, Borrowings Outstanding	$ 156,406,000	$ 156,406,000			$ 0
Secured Debt | Revolving Credit Facility | Revolver A Facility
Debtor-in-Possession Financing, Amount Arranged			125,000,000
Debtor-in-Possession Financing, Unused Borrowing Capacity, Amount	$ 81,600,000	$ 81,600,000
Secured Debt | Revolving Credit Facility | Revolver B Facility
Debtor-in-Possession Financing, Amount Arranged			$ 125,000,000
Unsecured Debt | Senior Unsecured Notes due 2018
Debt instrument, principal outstanding				131,600,000
Unsecured Debt | Senior Unsecured Notes due 2022
Debt instrument, principal outstanding				$ 70,200,000
Acadian Gas Pipeline System Case
Natural Gas Reservation Agreement, Volume Transported Or Sold Per Day | MMBTU	325,000
Enterprise Products Operating LLC
Natural Gas, Amount That Can Be Sold Per Day. Per Agreement | MMBTU	75,000
Regency Intrastate Gas Systems LLC
Natural Gas Reservation Agreement, Volume Transported Or Sold Per Day | MMBTU	237,500
Shell Energy North America LP
Natural Gas Reservation Agreement, Volume Transported Or Sold Per Day | MMBTU	100,000
OPCO
Working interest in equity investment		0.50%
East Texas/North Louisiana JV
Ownership percentage in joint venture	50.00%	50.00%
Appalachia Joint Venture
Ownership percentage in joint venture	50.00%	50.00%
Proportional working interest		49.75%

Organization And Basis Of Pre29

Organization And Basis Of Presentation Items Related to Reorganization Process (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Liabilities Subject to Compromise [Abstract]
Current maturities of long-term debt	$ 927,917		$ 0
Accrued interest payable	34,281
Accounts payable, accrued expenses and other liabilities	118,710
Liabilities related to rejected executory contracts	415,963
Liabilities subject to compromise	1,496,871		$ 0
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations	$ 21,900
Liabilities Subject to Compromise, Debt, Interest Rate	12.50%
Reorganization Items [Abstract]
Legal and professional fees	$ 13,850
Deferred financing costs, debt discounts and deferred reductions in carrying value	29,853
Rejection of executory contracts	309,197
Reorganization Items	$ 352,900	$ 0

Summary of Significant Accoun30

Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle
Net Cash Provided by (Used in) Investing Activities	$ (52,024)	$ (15,580)
Accounting Standards Update 2016-18
New Accounting Pronouncements or Change in Accounting Principle
Net Cash Provided by (Used in) Investing Activities	$ 4,400

Acquisitions, Divestitures an31

Acquisitions, Divestitures and Other Significant Events (Details) $ in Thousands	Mar. 01, 2018USD ($)	Feb. 27, 2018USD ($)aMcfe	Mar. 31, 2018USD ($)	Mar. 31, 2017USD ($)
Business Acquisition
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$ 129,100
Gain on Appalachia JV Settlement	119,500		$ 119,477	$ 0
Equity Method Investments		$ 9,600
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Unproved Oil and Natural Gas Properties	33,542
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Proved Developed and Undeveloped Oil and Natural Gas Properties, Net	72,548
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets	18,109
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Asset Retirement Obligations	2,315
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Loss Contracts	12,100
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Loss Contracts, Current	2,200
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Loss Contract, Noncurrent	$ 9,900
Appalachia Joint Venture
Business Acquisition
Gas And Oil Area, Reconveyed Interest | a		364
Gas And Oil Area, Reconveyed Interest, Consideration		$ 700
Gas And Oil Area, Increase | a		177,700
Gas And Oil Area, Production Of Acquired Wells, Per Day | Mcfe		26
OPCO And Appalachia Midstream JV
Business Acquisition
Equity Method Investment, Ownership Percentage		100.00%	50.00%
OPCO
Business Acquisition
Equity Method Investment, Ownership Percentage			50.00%
OPCO
Business Acquisition
Proceeds From Related Party, General And Administrative Services			$ 1,700

Acquisitions, Divestitures An32

Acquisitions, Divestitures And Other Significant Events Fair Value of Net Assets Acquired (Details) $ in Thousands	Mar. 01, 2018USD ($)
Fair Value of Net Assets Acquired [Abstract]
Cash and cash equivalents	$ 14,832
Accounts receivable, net	6,493
Unproved oil and natural gas properties	5,264
Unproved oil and natural gas properties	33,542
Proved developed and undeveloped oil and natural gas properties, net	72,548
Other assets	18,109
Accounts payable and accrued liabilities	(9,478)
Asset retirement obligations	(2,315)
Other long-term liabilities	(9,895)
Fair value of net assets acquired	$ 129,100

Acquisitions, Divestitures An33

Acquisitions, Divestitures And Other Significant Events Pro Forma Results of Operation (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Business Combinations, Pro Forma Results of Operation [Abstract]
Oil and natural gas revenues	$ 94,543	$ 83,557
Net income (loss)	$ (209,789)	$ 10,159
Basic earnings (loss) per share	$ (9.58)	$ 0.54
Diluted earnings (loss) per share	$ (9.58)	$ 0.54

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule of Reconciliation of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of period	$ 12,017
Liabilities incurred during the period	0
Revisions in estimated assumptions	(1)
Liabilities settled during the period	(7)
Adjustment to liability due to acquisitions (1)	2,315
Asset Retirement Obligations Reduction Due To Divestitures	(7)
Accretion of discount	241
Asset retirement obligations at end of period	14,558
Less current portion	600	$ 600
Long-term portion	$ 13,958

Oil and Natural Gas Propertie35

Oil and Natural Gas Properties (Narrative) (Details)	3 Months Ended		12 Months Ended
	Mar. 31, 2018USD ($)$ / MMBTU$ / bbl	Mar. 31, 2017USD ($)	Dec. 31, 2017$ / MMBTU$ / bbl
Oil and Gas Property [Abstract]
Impairment of unproved costs to proved properties	$ 0	$ 0
Reference Prices Per Bbl Of Oil | $ / bbl	53.49		51.34
Reference prices per mmbtu of natural gas | $ / MMBTU	3		2.98
Impairment of oil and natural gas properties	$ 0	$ 0
Discount rate	10.00%

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Net income (loss)	$ (211,049)	$ 8,193
Weighted average common shares outstanding	21,902	18,726
Net income (loss) per basic common share	$ (9.64)	$ 0.44
Weighted average common and common share equivalents outstanding	21,902	18,749
Net income (loss) per diluted common share	$ (9.64)	$ 0.44
Restricted Shares
Dilutive effect of restricted shares and restricted share units	0	23

Earnings Per Share (Details Tex

Earnings Per Share (Details Textual) - $ / shares	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Mar. 15, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share
Class of Warrant or Right, Exercise Price of Warrants or Rights	$ 0.01
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	12,640,295	3,232,222
1.5 Lien Notes | Secured Debt | Financing Warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share
Class of Warrant or Right, Exercise Price of Warrants or Rights	$ 13.95		$ 13.95

Derivative Financial Instrume38

Derivative Financial Instruments (Fair Value Of Derivative Financial Instruments) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value
Derivative financial instruments - commodity derivatives - Current assets	$ 0	$ 1,150
Warrant Liability, Liabilities Subject to Compromise	(1,767)
Derivative financial instruments - common share warrants - Long-term liabilities	$ 0	$ (1,950)

Derivative Financial Instrume39

Derivative Financial Instruments (Effect Of Derivative Financial Instruments) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivative Instruments, Gain (Loss)
Gain (loss) on derivative financial instruments - commodity derivatives	$ (615)	$ 15,533
Gain on derivative financial instruments - common share warrants	$ 183	$ 6,004

Derivative Financial Instrume40

Derivative Financial Instruments (Narrative) (Details) $ / shares in Units, MMBTU in Thousands, $ in Thousands	1 Months Ended	3 Months Ended
	Feb. 28, 2018USD ($)	Mar. 31, 2018USD ($)$ / shares	Mar. 31, 2017USD ($)	Jan. 16, 2018$ / sharesshares	Dec. 31, 2017MMBTU$ / MMBTU	Mar. 15, 2017$ / sharesshares
Derivative Financial Instruments
Class of Warrant or Right, Exercise Price of Warrants or Rights		$ 0.01
Price per share required for anti-dilution adjustment related to Commitment Fee Warrants and Amendment Fee Warrants		$ 10.5
Gain on derivative financial instruments - common share warrants | $		$ 183	$ 6,004
Natural Gas | Swap
Derivative Financial Instruments
Natural gas volume | MMBTU					3,650
Derivative, Average Price Risk Option Strike Price | $ / MMBTU					3.15
Proceeds from Derivative Instrument, Investing Activities | $	$ 500
Secured Debt | Financing Warrants | 1.5 Lien Notes
Derivative Financial Instruments
Class of Warrant or Right, Number of Securities Called by Warrants or Rights | shares						21,505,383
Class of Warrant or Right, Exercise Price of Warrants or Rights		$ 13.95				$ 13.95
Secured Debt | Commitment Fee Warrants | 1.5 Lien Notes
Derivative Financial Instruments
Class of Warrant or Right, Number of Securities Called by Warrants or Rights | shares						431,433
Class of Warrant or Right, Exercise Price of Warrants or Rights						$ 0.01
Secured Debt | Amendment Fee Warrants | 1.75 Lien Notes
Derivative Financial Instruments
Class of Warrant or Right, Number of Securities Called by Warrants or Rights | shares						1,325,546
Class of Warrant or Right, Exercise Price of Warrants or Rights						$ 0.01
Fairfax | Secured Debt | Financing Warrants | 1.5 Lien Notes
Derivative Financial Instruments
Class of Warrant or Right, Number of Securities Called by Warrants or Rights | shares				10,824,376
Class of Warrant or Right, Exercise Price of Warrants or Rights				$ 13.95
Fairfax | Secured Debt | 2017 Warrants
Derivative Financial Instruments
Class of Warrant or Right, Number of Securities Called by Warrants or Rights | shares				1,725,576
Class of Warrant or Right, Exercise Price of Warrants or Rights				$ 0.01

Debt (Schedule Of Long-Term Deb

Debt (Schedule Of Long-Term Debt) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Jan. 15, 2018	Dec. 31, 2017
Debt Instrument
Debt Instrument		$ 1,400,000
Deferred financing costs, net	$ 0		$ (11,281)
Total Debt	1,401,281		1,362,500
Liabilities Subject to Compromise, Debt Outstanding	927,917		0
Current maturities of long-term debt	473,364		1,362,500
Revolving Credit Facility | EXCO Resources Credit Agreement
Debt Instrument
Revolving credit facility under credit agreement	0		126,401
Debt Instrument		126,400
Secured Debt | 1.5 Lien Notes
Debt Instrument
Long-term Debt	316,958		176,560
Debt Instrument		317,000
Secured Debt | 1.75 Lien Notes
Debt Instrument
Long-term Debt	708,926		845,763
Debt Instrument		708,900
Secured Debt | Second Lien Term Loan
Debt Instrument
Long-term Debt	17,246		23,543
Debt Instrument		17,200
Secured Debt | Revolving Credit Facility
Debt Instrument
Debtor-in-Possession Financing, Borrowings Outstanding	156,406		0
Unsecured Debt | Senior Unsecured Notes due 2018
Debt Instrument
Long-term Debt	131,576		131,345
Debt Instrument		131,600
Unsecured Debt | Senior Unsecured Notes due 2022
Debt Instrument
Long-term Debt	$ 70,169		$ 70,169
Debt Instrument		$ 70,200

Debt (Narrative) (Details)

Debt (Narrative) (Details) - USD ($)	Jan. 22, 2018	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument
Debtor Reorganization Items, Write-off of Debt Issuance Costs and Debt Discounts		$ 24,400,000
Debtor Reorganization Items, Debtor-in-Possession Facility Financing Costs		$ 5,400,000
Debtor-In-Possession Financing, Maturity, Number Of Months From Initial Borrowings	12 months
Debtor-In-Possession Financing, Maturity, Option To Extend, Number Of Months From Initial Borrowings	18 months
Debtor-In-Possession Financing, Redetermination Of Borrowing Base, Percent Of Net Present Value	66.66%
Debtor-In-Possession Financing, Redetermination Of Borrowing Base, Discount Rate	9.00%
Debtor-In-Possession Financing, Percent Of Lien On Equity Interests In Each Direct And Indirect Subsidiary	100.00%
Debtor-In-Possession Financing, Covenant Terms, Minimum Cash And Unused Commitment Amount	$ 20,000,000
Debtor-in-Possession Financing, Covenant Terms, Percentage Of Aggregate Disbursement In Excess Of Thirteen Week Forecast, Maximum	120.00%
Debt Instrument, Covenant Compliance		we were in compliance with all of the covenants under the DIP Credit Agreement.
London Interbank Offered Rate (LIBOR)
Debt Instrument
Debtor-in-Possession Financing, Basis Spread On Variable Rate	4.00%
Alternate Base Rate (ABR)
Debt Instrument
Debtor-in-Possession Financing, Basis Spread On Variable Rate	2.00%
Revolving Credit Facility | Secured Debt
Debt Instrument
Debtor-in-Possession Financing, Amount Arranged	$ 250,000,000
Debtor-in-Possession Financing, Borrowings Outstanding		$ 156,406,000	$ 0
Revolving Credit Facility | EXCO Resources Credit Agreement
Debt Instrument
Debtor-In-Possession Financing, Proceeds Used To Refinance Debt Obligations	104,000,000
Debtor-In-Possession Financing, Outstanding Borrowings Deemed Exchanged For Loans	21,600,000
Revolving Credit Facility | Revolver A Facility | Secured Debt
Debt Instrument
Debtor-in-Possession Financing, Amount Arranged	125,000,000
Debtor-in-Possession Financing, Letters of Credit Outstanding	24,000,000	12,000,000
Debtor-in-Possession Financing, Unused Borrowing Capacity, Amount		$ 81,600,000
Revolving Credit Facility | Revolver B Facility | Secured Debt
Debt Instrument
Debtor-in-Possession Financing, Amount Arranged	$ 125,000,000

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule Of Estimated Fair Value Of Derivative Financial Instruments) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Commodity Contract
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value		$ 1,150
Commodity Contract | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value		0
Commodity Contract | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value		1,150
Commodity Contract | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value		0
Common Share Warrants
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value	$ 1,767	1,950
Common Share Warrants | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value	0	0
Common Share Warrants | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value	1,767	1,950
Common Share Warrants | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value	$ 0	$ 0

Fair Value Measurements (Sche44

Fair Value Measurements (Schedule Of Estimated Fair Value Of Other Financial Instruments) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
1.5 Lien Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$ 248,128	$ 232,276
1.5 Lien Notes | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0	0
1.5 Lien Notes | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0	0
1.5 Lien Notes | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	248,128	232,276
1.75 Lien Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	311,927	372,186
1.75 Lien Notes | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0	0
1.75 Lien Notes | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0	0
1.75 Lien Notes | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	311,927	372,186
Second Lien Term Loan
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	7,588	9,054
Second Lien Term Loan | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0	0
Second Lien Term Loan | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0	0
Second Lien Term Loan | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	7,588	9,054
Senior Unsecured Notes due 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	13,198	4,658
Senior Unsecured Notes due 2018 | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	13,198	4,658
Senior Unsecured Notes due 2018 | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0	0
Senior Unsecured Notes due 2018 | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0	0
Senior Unsecured Notes due 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	7,135	2,586
Senior Unsecured Notes due 2022 | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	7,135	2,586
Senior Unsecured Notes due 2022 | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0	0
Senior Unsecured Notes due 2022 | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$ 0	$ 0

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Change in valuation allowance	$ 43,300
Recognized net valuation allowance	886,800
Operating Loss Carryforwards	2,100,000
Deferred Tax Liabilities, Goodwill			$ 4,500
Income tax expense (benefit)	$ (4,518)	$ 1,028

Condensed Consolidating Finan46

Condensed Consolidating Financial Statements (Schedule Of Condensed Consolidating Balance Sheet) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 65,830	$ 39,597
Restricted cash	9,832	15,271
Other current assets	129,707	112,962
Total current assets	205,369	167,830
Equity investments	4,736	14,181
Unproved oil and natural gas properties and development costs not being amortized	149,322	118,652
Proved developed and undeveloped oil and natural gas properties	3,239,618	3,107,566
Accumulated depletion	(2,770,278)	(2,752,311)
Oil and natural gas properties, net	618,662	473,907
Other property and equipment, net and other non-current assets	39,345	21,274
Investments in and (advances to) affiliates, net	0	0
Goodwill	163,155	163,155
Total assets	1,031,267	840,347
Liabilities and shareholders’ equity
Current maturities of long-term debt	473,364	1,362,500
Other current liabilities	93,832	304,470
Derivative financial instruments - common share warrants	0	1,950
Other long-term liabilities	23,853	17,626
Liabilities subject to compromise	1,496,871	0
Intercompany payable to parent	0	0
Total shareholders’ equity	(1,056,653)	(846,199)	$ (865,443)	$ (871,906)
Total liabilities and shareholders’ equity	1,031,267	840,347
Reportable Legal Entities | Parent Company
Current assets:
Cash and cash equivalents	61,889	49,170
Restricted cash	552	0
Other current assets	11,056	22,697
Total current assets	73,497	71,867
Equity investments	0	0
Unproved oil and natural gas properties and development costs not being amortized	0	0
Proved developed and undeveloped oil and natural gas properties	334,199	333,719
Accumulated depletion	(330,776)	(330,777)
Oil and natural gas properties, net	3,423	2,942
Other property and equipment, net and other non-current assets	1,013	892
Investments in and (advances to) affiliates, net	306,795	466,055
Goodwill	13,293	13,293
Total assets	398,021	555,049
Liabilities and shareholders’ equity
Current maturities of long-term debt	473,364	1,362,500
Other current liabilities	15,452	32,280
Derivative financial instruments - common share warrants		1,950
Other long-term liabilities	0	4,518
Liabilities subject to compromise	965,858
Intercompany payable to parent	0	0
Total shareholders’ equity	(1,056,653)	(846,199)
Total liabilities and shareholders’ equity	398,021	555,049
Reportable Legal Entities | Guarantor Subsidiaries
Current assets:
Cash and cash equivalents	(11,791)	(9,573)
Restricted cash	9,280	15,271
Other current assets	110,931	90,265
Total current assets	108,420	95,963
Equity investments	0	0
Unproved oil and natural gas properties and development costs not being amortized	115,780	118,652
Proved developed and undeveloped oil and natural gas properties	2,832,863	2,773,847
Accumulated depletion	(2,438,901)	(2,421,534)
Oil and natural gas properties, net	509,742	470,965
Other property and equipment, net and other non-current assets	20,285	20,382
Investments in and (advances to) affiliates, net	0	0
Goodwill	149,862	149,862
Total assets	788,309	737,172
Liabilities and shareholders’ equity
Current maturities of long-term debt	0	0
Other current liabilities	71,055	272,190
Derivative financial instruments - common share warrants		0
Other long-term liabilities	11,631	13,108
Liabilities subject to compromise	531,013
Intercompany payable to parent	2,458,854	2,447,586
Total shareholders’ equity	(2,284,244)	(1,995,712)
Total liabilities and shareholders’ equity	788,309	737,172
Reportable Legal Entities | Non-Guarantor Subsidiaries
Current assets:
Cash and cash equivalents	15,732	0
Restricted cash	0	0
Other current assets	7,720	0
Total current assets	23,452	0
Equity investments	4,736	14,181
Unproved oil and natural gas properties and development costs not being amortized	33,542	0
Proved developed and undeveloped oil and natural gas properties	72,556	0
Accumulated depletion	(601)	0
Oil and natural gas properties, net	105,497	0
Other property and equipment, net and other non-current assets	18,047	0
Investments in and (advances to) affiliates, net	0	0
Goodwill	0	0
Total assets	151,732	14,181
Liabilities and shareholders’ equity
Current maturities of long-term debt	0	0
Other current liabilities	7,325	0
Derivative financial instruments - common share warrants		0
Other long-term liabilities	12,222	0
Liabilities subject to compromise	0
Intercompany payable to parent	(1,518)	0
Total shareholders’ equity	133,703	14,181
Total liabilities and shareholders’ equity	151,732	14,181
Consolidation, Eliminations
Current assets:
Cash and cash equivalents	0	0
Restricted cash	0	0
Other current assets	0	0
Total current assets	0	0
Equity investments	0	0
Unproved oil and natural gas properties and development costs not being amortized	0	0
Proved developed and undeveloped oil and natural gas properties	0	0
Accumulated depletion	0	0
Oil and natural gas properties, net	0	0
Other property and equipment, net and other non-current assets	0	0
Investments in and (advances to) affiliates, net	(306,795)	(466,055)
Goodwill	0	0
Total assets	(306,795)	(466,055)
Liabilities and shareholders’ equity
Current maturities of long-term debt	0	0
Other current liabilities	0	0
Derivative financial instruments - common share warrants		0
Other long-term liabilities	0	0
Liabilities subject to compromise	0
Intercompany payable to parent	(2,457,336)	(2,447,586)
Total shareholders’ equity	2,150,541	1,981,531
Total liabilities and shareholders’ equity	$ (306,795)	$ (466,055)

Condensed Consolidating Finan47

Condensed Consolidating Financial Statements (Schedule Of Condensed Consolidating Statement Of Operations) (Details) - USD ($) $ in Thousands	Mar. 01, 2018	Mar. 31, 2018	Mar. 31, 2017
Revenues:
Oil and natural gas		$ 85,146	$ 69,356
Purchased natural gas and marketing		5,318	7,173
Total revenues		90,464	76,529
Costs and expenses:
Oil and natural gas production		11,904	11,933
Gathering and transportation		19,976	27,353
Purchased natural gas		4,115	6,452
Depletion, depreciation and amortization		18,206	11,508
Impairment of oil and natural gas properties		0	0
Accretion of liabilities		342	212
General and administrative		8,527	4,415
Gain on Appalachia JV Settlement	$ (119,500)	(119,477)	0
Other operating items		134	1,069
Total costs and expenses		(56,273)	62,942
Operating income		146,737	13,587
Other expense:
Interest expense, net		(9,173)	(19,952)
Gain (loss) on derivative financial instruments - commodity derivatives		(615)	15,533
Gain on derivative financial instruments - common share warrants		183	6,004
Loss on restructuring and extinguishment of debt		0	(6,272)
Other income (loss)		22	4
Equity income		179	317
Reorganization items, net		(352,900)	0
Net earnings (loss) from consolidated subsidiaries		0	0
Total other expense		(362,304)	(4,366)
Income (loss) before income taxes		(215,567)	9,221
Income tax expense		(4,518)	1,028
Net income (loss)		(211,049)	8,193
Reportable Legal Entities | Parent Company
Revenues:
Oil and natural gas		0	0
Purchased natural gas and marketing		0	0
Total revenues		0	0
Costs and expenses:
Oil and natural gas production		0	0
Gathering and transportation		0	0
Purchased natural gas		0	0
Depletion, depreciation and amortization		80	61
Accretion of liabilities		0	0
General and administrative		(6,780)	(10,667)
Gain on Appalachia JV Settlement		0
Other operating items		(34)	398
Total costs and expenses		(6,734)	(10,208)
Operating income		6,734	10,208
Other expense:
Interest expense, net		(9,173)	(19,952)
Gain (loss) on derivative financial instruments - commodity derivatives		(615)	15,533
Gain on derivative financial instruments - common share warrants		183	6,004
Loss on restructuring and extinguishment of debt			(6,272)
Other income (loss)		17	1
Equity income		0	0
Reorganization items, net		(43,703)
Net earnings (loss) from consolidated subsidiaries		(169,010)	3,699
Total other expense		(222,301)	(987)
Income (loss) before income taxes		(215,567)	9,221
Income tax expense		(4,518)	1,028
Net income (loss)		(211,049)	8,193
Reportable Legal Entities | Guarantor Subsidiaries
Revenues:
Oil and natural gas		83,296	69,356
Purchased natural gas and marketing		5,318	7,173
Total revenues		88,614	76,529
Costs and expenses:
Oil and natural gas production		11,447	11,933
Gathering and transportation		19,651	27,353
Purchased natural gas		4,115	6,452
Depletion, depreciation and amortization		17,463	11,447
Accretion of liabilities		229	212
General and administrative		14,872	15,082
Gain on Appalachia JV Settlement		0
Other operating items		9,800	671
Total costs and expenses		77,577	73,150
Operating income		11,037	3,379
Other expense:
Interest expense, net		0	0
Gain (loss) on derivative financial instruments - commodity derivatives		0	0
Gain on derivative financial instruments - common share warrants		0	0
Loss on restructuring and extinguishment of debt			0
Other income (loss)		5	3
Equity income		179	0
Reorganization items, net		(309,197)
Net earnings (loss) from consolidated subsidiaries		0	0
Total other expense		(309,013)	3
Income (loss) before income taxes		(297,976)	3,382
Income tax expense		0	0
Net income (loss)		(297,976)	3,382
Reportable Legal Entities | Non-Guarantor Subsidiaries
Revenues:
Oil and natural gas		1,850	0
Purchased natural gas and marketing		0	0
Total revenues		1,850	0
Costs and expenses:
Oil and natural gas production		457	0
Gathering and transportation		325	0
Purchased natural gas		0	0
Depletion, depreciation and amortization		663	0
Accretion of liabilities		113	0
General and administrative		435	0
Gain on Appalachia JV Settlement		(119,477)
Other operating items		(9,632)	0
Total costs and expenses		(127,116)	0
Operating income		128,966	0
Other expense:
Interest expense, net		0	0
Gain (loss) on derivative financial instruments - commodity derivatives		0	0
Gain on derivative financial instruments - common share warrants		0	0
Loss on restructuring and extinguishment of debt			0
Other income (loss)		0	0
Equity income		0	317
Reorganization items, net		0
Net earnings (loss) from consolidated subsidiaries		0	0
Total other expense		0	317
Income (loss) before income taxes		128,966	317
Income tax expense		0	0
Net income (loss)		128,966	317
Consolidation, Eliminations
Revenues:
Oil and natural gas		0	0
Purchased natural gas and marketing		0	0
Total revenues		0	0
Costs and expenses:
Oil and natural gas production		0	0
Gathering and transportation		0	0
Purchased natural gas		0	0
Depletion, depreciation and amortization		0	0
Accretion of liabilities		0	0
General and administrative		0	0
Gain on Appalachia JV Settlement		0
Other operating items		0	0
Total costs and expenses		0	0
Operating income		0	0
Other expense:
Interest expense, net		0	0
Gain (loss) on derivative financial instruments - commodity derivatives		0	0
Gain on derivative financial instruments - common share warrants		0	0
Loss on restructuring and extinguishment of debt			0
Other income (loss)		0	0
Equity income		0	0
Reorganization items, net		0
Net earnings (loss) from consolidated subsidiaries		169,010	(3,699)
Total other expense		169,010	(3,699)
Income (loss) before income taxes		169,010	(3,699)
Income tax expense		0	0
Net income (loss)		$ 169,010	$ (3,699)

Condensed Consolidating Finan48

Condensed Consolidating Financial Statements (Schedule Of Condensed Consolidating Statement Of Cash Flows) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Net cash provided by (used in) operating activities	$ 48,252	$ 5,196
Net Cash Provided by (Used in) Investing Activities [Abstract]
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(52,024)	(11,857)
Advances (to) from Joint Ventures	0	3,723
Advances And Investments With Affiliates		0
Net cash used in investing activities	(52,024)	(15,580)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Borrowings under DIP Credit Agreement	156,406	0
Borrowings under EXCO Resources Credit Agreement	0	25,000
Repayments under EXCO Resources Credit Agreement	(126,401)	(253,592)
Proceeds received from issuance of 1.5 Lien Notes, net	0	295,530
Payments on Second Lien Term Loans	0	(10,512)
Debt financing costs and other	(5,439)	(18,636)
Net cash provided by financing activities	24,566	37,790
Net increase in cash, cash equivalents and restricted cash	20,794	27,406
Cash, cash equivalents and restricted cash at beginning of period	54,868	20,218
Cash, cash equivalents and restricted cash at end of period	75,662	47,624
Reportable Legal Entities | Parent Company
Net cash provided by (used in) operating activities	(10,768)	(12,106)
Net Cash Provided by (Used in) Investing Activities [Abstract]
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(527)	(271)
Advances (to) from Joint Ventures		0
Advances And Investments With Affiliates		6,998
Net cash used in investing activities	(527)	(7,269)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Borrowings under DIP Credit Agreement	156,406
Borrowings under EXCO Resources Credit Agreement		25,000
Repayments under EXCO Resources Credit Agreement	(126,401)	(253,592)
Proceeds received from issuance of 1.5 Lien Notes, net		295,530
Payments on Second Lien Term Loans		(10,512)
Debt financing costs and other	(5,439)	(18,636)
Net cash provided by financing activities	24,566	37,790
Net increase in cash, cash equivalents and restricted cash	13,271	18,415
Cash, cash equivalents and restricted cash at beginning of period	49,170	24,610
Cash, cash equivalents and restricted cash at end of period	62,441	43,025
Reportable Legal Entities | Guarantor Subsidiaries
Net cash provided by (used in) operating activities	58,120	17,302
Net Cash Provided by (Used in) Investing Activities [Abstract]
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(66,329)	(11,586)
Advances (to) from Joint Ventures		3,723
Advances And Investments With Affiliates		(6,998)
Net cash used in investing activities	(66,329)	(8,311)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Borrowings under DIP Credit Agreement	0
Borrowings under EXCO Resources Credit Agreement		0
Repayments under EXCO Resources Credit Agreement	0	0
Proceeds received from issuance of 1.5 Lien Notes, net		0
Payments on Second Lien Term Loans		0
Debt financing costs and other	0	0
Net cash provided by financing activities	0	0
Net increase in cash, cash equivalents and restricted cash	(8,209)	8,991
Cash, cash equivalents and restricted cash at beginning of period	5,698	(4,392)
Cash, cash equivalents and restricted cash at end of period	(2,511)	4,599
Reportable Legal Entities | Non-Guarantor Subsidiaries
Net cash provided by (used in) operating activities	900	0
Net Cash Provided by (Used in) Investing Activities [Abstract]
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	14,832	0
Advances (to) from Joint Ventures		0
Advances And Investments With Affiliates		0
Net cash used in investing activities	14,832	0
Net Cash Provided by (Used in) Financing Activities [Abstract]
Borrowings under DIP Credit Agreement	0
Borrowings under EXCO Resources Credit Agreement		0
Repayments under EXCO Resources Credit Agreement	0	0
Proceeds received from issuance of 1.5 Lien Notes, net		0
Payments on Second Lien Term Loans		0
Debt financing costs and other	0	0
Net cash provided by financing activities	0	0
Net increase in cash, cash equivalents and restricted cash	15,732	0
Cash, cash equivalents and restricted cash at beginning of period	0	0
Cash, cash equivalents and restricted cash at end of period	15,732	0
Consolidation, Eliminations
Net cash provided by (used in) operating activities	0	0
Net Cash Provided by (Used in) Investing Activities [Abstract]
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	0	0
Advances (to) from Joint Ventures		0
Advances And Investments With Affiliates		0
Net cash used in investing activities	0	0
Net Cash Provided by (Used in) Financing Activities [Abstract]
Borrowings under DIP Credit Agreement	0
Borrowings under EXCO Resources Credit Agreement		0
Repayments under EXCO Resources Credit Agreement	0	0
Proceeds received from issuance of 1.5 Lien Notes, net		0
Payments on Second Lien Term Loans		0
Debt financing costs and other	0	0
Net cash provided by financing activities	0	0
Net increase in cash, cash equivalents and restricted cash	0	0
Cash, cash equivalents and restricted cash at beginning of period	0	0
Cash, cash equivalents and restricted cash at end of period	$ 0	$ 0