Exco Resources (EXCO) 10-K 2 Mar 16 2015 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Feb. 25, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Entity Registrant Name	EXCO RESOURCES INC
Entity Central Index Key	316,300
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		282,924,079
Entity Current Reporting Status	Yes
Entity Public Float			$ 186,183
Entity Voluntary Filers	No
Entity Well-known Seasonal Issuer	No

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 12,247	$ 46,305
Restricted cash	21,220	23,970
Accounts receivable, net:
Oil and natural gas	37,236	81,720
Joint interest	22,095	65,398
Other	8,894	8,945
Derivative financial instruments	39,499	97,278
Inventory and other	8,610	7,150
Total current assets	149,801	330,766
Equity investments	40,797	55,985
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	115,377	276,025
Proved developed and undeveloped oil and natural gas properties	3,070,430	3,852,073
Accumulated depletion	(2,627,763)	(2,414,461)
Oil and natural gas properties, net	558,044	1,713,637
Other property and equipment, net	27,812	24,644
Deferred financing costs, net	8,408	14,617
Derivative financial instruments	6,109	2,138
Goodwill	163,155	163,155
Total assets	954,126	2,304,942
Current liabilities:
Accounts payable and accrued liabilities	85,254	110,211
Revenues and royalties payable	106,163	152,651
Drilling advances	2,795	37,648
Accrued interest payable	7,846	26,265
Current portion of asset retirement obligations	845	1,769
Income taxes payable	0	0
Derivative financial instruments	16	892
Current portion of long-term debt	50,000	0
Total current liabilities	252,919	329,436
Long-term debt	1,320,279	1,430,516
Asset retirement obligations and other long-term liabilities	43,251	34,986
Shareholders’ equity:
Common shares, $0.001 par value; 780,000,000 authorized shares; 283,633,996 shares issued and 283,039,333 shares outstanding at December 31, 2015; 274,351,756 shares issued and 273,773,714 shares outstanding at December 31, 2014	276	270
Additional paid-in capital	3,522,153	3,502,209
Accumulated deficit	(4,177,120)	(2,984,860)
Treasury shares, at cost; 594,663 at December 31, 2015 and 578,042 at December 31, 2014	(7,632)	(7,615)
Total shareholders' equity	(662,323)	510,004
Total liabilities and shareholders' equity	$ 954,126	$ 2,304,942

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.001	$ 0.001
Common stock, authorized shares	780,000,000	350,000,000
Common stock, shares issued	283,633,996	274,351,756
Common stock, shares outstanding	283,039,333	273,773,714
Treasury stock, shares	594,663	578,042

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Oil	$ 102,787	$ 196,316	$ 111,440
Natural gas	225,544	463,953	522,869
Total revenues	328,331	660,269	634,309
Costs and expenses:
Oil and natural gas operating costs	53,903	64,467	61,277
Production and ad valorem taxes	22,630	29,859	21,971
Gathering and transportation	99,321	101,574	100,645
Depletion, depreciation and amortization	215,426	263,569	245,775
Impairment of oil and natural gas properties	1,215,370	0	108,546
Accretion of discount on asset retirement obligations	2,277	2,690	2,514
General and administrative	58,818	65,920	91,878
(Gain) loss on divestitures and other operating items	461	5,315	(177,518)
Total costs and expenses	1,668,206	533,394	455,088
Operating income (loss)	(1,339,875)	126,875	179,221
Other income (expense):
Interest expense, net	(106,082)	(94,284)	(102,589)
Gain (loss) on derivative financial instruments	75,869	87,665	(320)
Gain on restructuring and extinguishment of debt	193,276	0	0
Other income (expense)	122	241	(828)
Equity income (loss)	(15,691)	172	(53,280)
Total other income (expense)	147,494	(6,206)	(157,017)
Income (loss) before income taxes	(1,192,381)	120,669	22,204
Income tax expense	0	0	0
Net income (loss)	$ (1,192,381)	$ 120,669	$ 22,204
Basic:
Net income (loss) (in dollars per share)	$ (4.36)	$ 0.45	$ 0.10
Weighted average common shares outstanding	273,621	268,258	215,011
Diluted:
Net income (loss) (in dollars per share)	$ (4.36)	$ 0.45	$ 0.10
Weighted average common shares and common share equivalents outstanding	273,621	268,376	230,912

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Activities:
Net income (loss)	$ (1,192,381)	$ 120,669	$ 22,204
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	215,426	263,569	245,775
Equity-based compensation expense	7,198	4,962	10,748
Accretion of discount on asset retirement obligations	2,277	2,690	2,514
Impairment of oil and natural gas properties	1,215,370	0	108,546
(Income) loss from equity investments	15,691	(172)	53,280
(Gain) loss on derivative financial instruments	(75,869)	(87,665)	320
Cash settlements (payments) of derivative financial instruments	128,800	(18,991)	42,119
Amortization of deferred financing costs and discount on debt issuance	16,994	12,055	29,624
Gain on divestitures and other non-operating items	(32)	(17)	(185,163)
Gain on restructuring and extinguishment of debt	(193,276)	0	0
Effect of changes in:
Restricted cash with related party	(2,100)	0	0
Accounts receivable	88,610	52,007	(46,176)
Other current assets	434	(2,609)	9,627
Accounts payable and other current liabilities	(93,115)	15,595	57,216
Net cash provided by operating activities	134,027	362,093	350,634
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment	(317,590)	(391,776)	(320,538)
Property acquisitions	(7,608)	(10,790)	(976,714)
Proceeds from disposition of property and equipment	7,397	187,655	749,628
Restricted cash	4,850	(3,400)	49,515
Net changes in advances to joint ventures	10,663	(5,026)	10,645
Equity investments and other	1,455	1,749	234,986
Net cash used in investing activities	(300,833)	(221,588)	(252,478)
Financing Activities:
Borrowings under credit agreements	165,000	100,000	1,004,523
Repayments under credit agreements	(300,000)	(964,970)	(1,022,785)
Proceeds received from issuance of 2022 Notes	0	500,000	0
Repurchases of 2018 Notes	(12,008)	0	0
Proceeds received from issuance of Fairfax Term Loan	300,000	0	0
Payment on Exchange Term Loan	(8,827)	0	0
Proceeds from issuance of common shares, net	9,693	271,773	1,712
Payment of common share dividends	(164)	(41,060)	(43,214)
Deferred financing costs and other	(20,946)	(10,426)	(33,553)
Net cash provided by (used in) financing activities	132,748	(144,683)	(93,317)
Net increase (decrease) in cash	(34,058)	(4,178)	4,839
Cash at beginning of period	46,305	50,483	45,644
Cash at end of period	12,247	46,305	50,483
Supplemental Cash Flow Information:
Cash interest payments	117,463	91,735	88,936
Income tax payments	0	0	0
Supplemental non-cash investing and financing activities:
Capitalized equity-based compensation	3,428	5,498	7,288
Capitalized interest	12,040	20,060	18,729
Issuance of common stock for director services	150	235	93
Debt eliminated upon sale of Compass and assumed upon formation of Compass, net for the years ended December 31, 2014 and 2013, respectively	$ 0	$ (83,246)	$ 58,613

Consolidated Statements Of Chan

Consolidated Statements Of Changes In Shareholders' Equity - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Subscription Rights	Treasury Stock	Additional paid-in capital	Accumulated deficit
Beginning Balance (in shares) at Dec. 31, 2012		218,126		(539)
Beginning Balance, Subscription Rights (in shares) at Dec. 31, 2012			0
Beginning Balance at Dec. 31, 2012	$ 149,393	$ 215	$ 0	$ (7,479)	$ 3,200,067	$ (3,043,410)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common shares (in shares)		228
Issuance of common shares	1,805	$ 0			1,805
Equity-based compensation	17,931				17,931
Restricted shares issued, net of cancellations (in shares)		429
Restricted shares issued, net of cancellations	0	$ 0
Common share dividends	(43,428)					(43,428)
Issuance of subscription rights (in shares)			54,575
Issuance of subscription rights			$ 55		(55)
Net income (loss)	22,204					22,204
Ending Balance at Dec. 31, 2013	147,905	$ 215	$ 55	$ (7,479)	3,219,748	(3,064,634)
Ending Balance, Subscription Rights (in shares) at Dec. 31, 2013			54,575
Ending Balance (in shares) at Dec. 31, 2013		218,783		(539)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common shares (in shares)		54,582	(54,575)
Issuance of common shares	272,008	$ 55	$ (55)		272,008
Equity-based compensation	10,453				10,453
Restricted shares issued, net of cancellations (in shares)		987
Restricted shares issued, net of cancellations	0	$ 0
Common share dividends	(40,895)					(40,895)
Treasury share repurchases (in shares)				(39)
Treasury share repurchases	(136)			$ (136)
Net income (loss)	120,669					120,669
Ending Balance at Dec. 31, 2014	510,004	$ 270	$ 0	$ (7,615)	3,502,209	(2,984,860)
Ending Balance, Subscription Rights (in shares) at Dec. 31, 2014			0
Ending Balance (in shares) at Dec. 31, 2014		274,352		(578)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common shares (in shares)		5,882	0
Issuance of common shares	9,844	$ 6	$ 0		9,838
Equity-based compensation	10,106				10,106
Restricted shares issued, net of cancellations (in shares)		3,400
Restricted shares issued, net of cancellations	0	$ 0
Common share dividends	121					121
Treasury share repurchases (in shares)				(17)
Treasury share repurchases	(17)			$ (17)
Net income (loss)	(1,192,381)					(1,192,381)
Ending Balance at Dec. 31, 2015	$ (662,323)	$ 276	$ 0	$ (7,632)	$ 3,522,153	$ (4,177,120)
Ending Balance, Subscription Rights (in shares) at Dec. 31, 2015			0
Ending Balance (in shares) at Dec. 31, 2015		283,634		(595)

Organization And Basis Of Prese

Organization And Basis Of Presentation	12 Months Ended
	Dec. 31, 2015
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 Annual Report on Form 10-K to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” are to EXCO Resources, Inc. and its consolidated subsidiaries. We are an independent oil and natural gas company engaged in the exploration, exploitation, acquisition, development and production of 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 BG Group, plc ("BG Group") covering an undivided 50% interest in certain Haynesville/Bossier shale assets in East Texas and North Louisiana. The East Texas and North Louisiana regions also include assets outside of the joint venture in the Haynesville and Bossier shales. We serve as the operator for most of our properties in both the East Texas and North Louisiana regions. • South Texas The South Texas region is primarily comprised of our Eagle Ford shale assets. We have a joint venture with affiliates of Kohlberg Kravis Roberts & Co. L.P. ("KKR") covering certain assets in the Eagle Ford shale. The South Texas region also includes assets outside of the joint venture in the Eagle Ford shale, Buda and other formations. We serve as the operator for most of our properties in the South Texas region. • Appalachia The Appalachia region is primarily comprised of Marcellus shale assets as well as shallow conventional assets in other formations. We have a joint venture with BG Group covering our shallow conventional assets and Marcellus shale assets in the Appalachia region ("Appalachia JV"). EXCO and BG Group each own an undivided 50% interest in the Appalachia JV and a 49.75% working interest in the Appalachia JV's properties. The remaining 0.5% working interest is held by a jointly owned operating entity ("OPCO") that operates the Appalachia JV's properties. We own a 50% interest in OPCO. The accompanying Consolidated Balance Sheets as of December 31, 2015 and 2014 , Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2015 , 2014 and 2013 are for EXCO and its subsidiaries. The 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.

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary of significant accounting policies	Summary of significant accounting policies Principles of consolidation We consolidate all of our subsidiaries in the accompanying Consolidated Balance Sheets as of December 31, 2015 and 2014 and the Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Changes in Shareholders' Equity for the years ended December 31, 2015 , 2014 and 2013 . Investments in unconsolidated affiliates in which we are able to exercise significant influence are accounted for using the equity method. We use the cost method of accounting for investments in unconsolidated affiliates in which we are not able to exercise significant influence. All intercompany transactions and accounts have been eliminated. We report our interests in oil and natural gas properties using the proportional consolidation method of accounting. We reported our 25.5% interest in Compass Production Partners, L.P. ("Compass") using proportional consolidation for the period from its formation on February 14, 2013 to the sale of our interests on October 31, 2014. See further discussion in "Note 3. Acquisitions, divestitures and other significant events." Management estimates In preparing the consolidated financial statements in conformity with GAAP, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses during the reporting periods. The more significant estimates pertain to proved oil and natural gas reserve volumes, future development costs, asset retirement obligations, equity-based compensation, estimates relating to oil and natural gas revenues and expenses, accrued liabilities, the fair market value of assets and liabilities acquired in business combinations, derivatives and goodwill. Actual results may differ from management's estimates. Cash equivalents We consider all highly liquid investments with maturities of three months or less when purchased, to be cash equivalents. Restricted cash The restricted cash on our balance sheet is principally comprised of our share of an evergreen escrow account with BG Group that is used to fund our share of development operations in East Texas and North Louisiana. Funds held in this escrow account are restricted and can be used primarily for drilling and operations in East Texas and North Louisiana. The restricted cash also includes accrued fees payable to Energy Strategic Advisory Services LLC ("ESAS") upon completion of its entire first year of service and required investment with EXCO. See "Note 13. Related party transactions" for furt her discussion of the services and investment agreement with ESAS. Concentration of credit risk and accounts receivable Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, trade receivables and our derivative financial instruments. We place our cash with financial institutions which we believe have sufficient credit quality to minimize risk of loss. We sell oil and natural gas to various customers. In addition, we participate with other parties in the drilling, completion and operation of oil and natural gas wells. The majority of our accounts receivable are due from either purchasers of oil or natural gas or participants in oil and natural gas wells for which we serve as the operator. We have the right to offset future revenues against unpaid charges related to wells which we operate. Oil and natural gas receivables are generally uncollateralized. The allowance for doubtful accounts was immaterial at both December 31, 2015 and 2014 . We place our derivative financial instruments with financial institutions that we believe have high credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with our counterparties on our derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty. For the years ended December 31, 2015 , 2014 and 2013 , sales to BG Energy Merchants LLC accounted for approximately 20% , 34% and 48% , respectively, of total consolidated revenues. BG Energy Merchants LLC is a subsidiary of BG Group. For the years ended December 31, 2015 , 2014 and 2013 , Chesapeake Energy Marketing Inc. accounted for approximately 38% , 31% and 14% respectively, of total consolidated revenues. Chesapeake Energy Marketing Inc. is a subsidiary of Chesapeake Energy Corporation ("Chesapeake"). Derivative financial instruments We use derivative financial instruments to mitigate the impacts of commodity price fluctuations, protect our returns on investments and achieve a more predictable cash flow. Financial Accounting Standards Board ("FASB"), Accounting Standards Codification, ("ASC"), Topic 815, Derivatives and Hedging, ("ASC 815"), requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its estimated fair value. ASC 815 requires that changes in the derivative's estimated fair value be recognized in earnings unless specific hedge accounting criteria are met, or exemptions for normal purchases and normal sales as permitted by ASC 815 exist. We do not designate our derivative financial instruments as hedging instruments and, as a result, recognize the change in a derivative's estimated fair value in earnings as a component of other income or expense. Our derivative financial instruments are not held for trading purposes. Oil and natural gas properties The accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives: the full cost method or the successful efforts method. 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. Our unproved property costs, which include unproved oil and natural gas properties, properties under development, and major development projects, collectively totaled $115.4 million and $276.0 million as of December 31, 2015 and 2014 , respectively, and are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extension or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. In determining whether such costs should be impaired or transferred, we evaluate lease expiration dates, recent drilling results, future development plans and current market values. Our undeveloped properties are predominantly held-by-production, which reduces the risk of impairment as a result of lease expirations. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. As a result of our evaluation, we impaired approximately $88.1 million of unproved properties which were transferred to the depletable portion of the full cost pool during the year ended December 31, 2015 . The impairment was recorded to reflect the estimated fair value of our undeveloped properties as a result of the decline in oil and natural gas prices. The impairment also included certain acreage expiring within the next year and related properties that were no longer part of our drilling plans. See "Note 6. Fair value measurements" for further discussion. We did no t record an impairment of undeveloped properties during 2014 and recorded an impairment of $1.0 million during 2013. We capitalize interest on the costs related to the acquisition of undeveloped acreage in accordance with FASB ASC 835-20 , Capitalization of Interest . When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we cease capitalizing interest related to these properties. We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs less estimated salvage value are divided by the total estimated quantities of Proved Reserves. This rate is applied to our total production for the quarter, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our acquisition, exploration, exploitation and development activities. Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the amortization rate and/or the relationship between capitalized costs and Proved Reserves. Pursuant to Rule 4-10(c)(4) of Regulation S-X, at the end of each quarterly period, companies that use the full cost method of accounting for their 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 a ceiling test 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 Release No. 33-8995, 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. The ceiling test for each period presented 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 12 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) December 31, 2015 $ 50.28 $ 2.59 December 31, 2014 94.99 4.35 December 31, 2013 96.78 3.67 For the year ended December 31, 2015 , we recognized impairments to our proved oil and natural gas properties of $1.2 billion . The impairments were primarily due to the decline in oil and natural gas prices partially offset by upward revisions in the oil and natural gas reserves primarily as a result of recent modifications to our well design in the North Louisiana and East Texas regions. For the year ended December 31, 2014, we did no t recognize an impairment to our proved oil and natural gas properties. For the year ended December 31, 2013, we recognized impairments of $108.5 million to our proved oil and natural gas properties. The impairments for the year ended December 31, 2013 were primarily due to low natural gas prices for the trailing 12 months at the end of the first quarter of 2013, downward revisions to the reserves of our Haynesville shale properties based on operational matters, narrowing of basis differentials between oil price indices, and higher costs associated with the gathering and transportation of our natural gas production from the Eagle Ford shale. We may incur additional impairments to our oil and natural gas properties in 2016 if oil and natural gas prices do not increase. Under full cost accounting rules, any ceiling test impairments of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedging instruments, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computations. The evaluation of impairment of our oil and natural gas properties includes estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of 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. Inventory Inventory includes tubular goods and other lease and well equipment which we plan to utilize in our ongoing exploration and development activities and is carried at the lower of cost or market value. The cost of inventory is capitalized in our full cost pool or gathering system assets once it has been placed into service. Other property and equipment Other property and equipment is primarily comprised of office, field and other equipment which are capitalized at cost and depreciated on a straight line basis over their estimated useful lives ranging from 3 to 15 years and the surface acreage we own in our South Texas region. Goodwill In accordance with FASB ASC 350-20, Intangibles-Goodwill and Other , goodwill is not amortized, but is tested for impairment on an annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed as of December 31 of each year. We performed impairment tests as of June 30, 2015 and September 30, 2015 as a result of continued depressed commodity prices and recent impairments of our oil and natural gas properties. Losses, if any, resulting from impairment tests will be reflected in operating income or loss in the Consolidated Statements of Operations. We apply a two-part, equally weighted approach in determining the fair value of our business as part of the goodwill impairment test. We perform an income approach, which uses a discounted cash flow model to value our business, and a market approach, in which our value is determined using trading metrics and transaction multiples of peer companies. We consider our enterprise value to be the combined market capitalization plus the fair value of our debt in determining the fair value of our reporting unit and corroborate the results with the valuation model. As a result of testing, the fair value of our business significantly exceeded the carrying value of net assets at December 31, 2015 and we did not record an impairment charge for the periods ending December 31, 2015, 2014 or 2013 . Asset retirement obligations We apply FASB ASC 410-20, Asset Retirement and Environmental Obligations ("ASC 410-20") to account for estimated future plugging and abandonment costs. ASC 410-20 requires legal obligations associated with the retirement of long-lived assets to be recognized at their estimated fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Our asset retirement obligations primarily represent the present value of the estimated amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state laws. The following is a reconciliation of our asset retirement obligations for the periods indicated: December 31, (in thousands) 2015 2014 2013 Asset retirement obligations at beginning of period $ 36,755 $ 42,954 $ 61,864 Activity during the period: Liabilities incurred during the period 881 576 514 Revisions in estimated assumptions 3,215 — 1,268 Liabilities settled during the period (293 ) (33 ) (187 ) Adjustment to liability due to acquisitions 180 107 5,566 Adjustment to liability due to divestitures (1) (1,367 ) (9,539 ) (28,585 ) Accretion of discount 2,277 2,690 2,514 Asset retirement obligations at end of period 41,648 36,755 42,954 Less current portion 845 1,769 191 Long-term portion $ 40,803 $ 34,986 $ 42,763 (1) For the year ended December 31, 2014, the adjustment to liability due to divestitures consisted primarily of $9.4 million from the sale of our interest in Compass. For the year ended December 31, 2013, the adjustment to liability due to divestitures consisted primarily of $28.3 million from the contribution of our certain conventional assets to Compass. 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. Revenue recognition and gas imbalances We use the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. Gas imbalances at December 31, 2015 , 2014 and 2013 were not significant. Gathering and transportation We generally sell oil and natural gas under two types of agreements which are common in our industry. Both types of agreements include a transportation charge. One is a net-back arrangement, under which we sell oil or natural gas at the wellhead and collect a price, net of the transportation incurred by the purchaser. In this case, we record sales at the price received from the purchaser, net of the transportation costs. Under the other arrangement, we sell oil or natural gas at a specific delivery point, pay transportation to a third party and receive proceeds from the purchaser with no transportation deduction. In this case, we record the transportation cost as gathering and transportation expense. As such, our computed realized prices, before the impact of derivative financial instruments, include revenues which are reported under two separate bases. Gathering and transportation expenses totaled $99.3 million , $101.6 million and $100.6 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Capitalization of internal costs As part of our proved developed oil and natural gas properties, we capitalize a portion of salaries and related share-based compensation for employees who are directly involved in the acquisition, exploration, exploitation and development of oil and natural gas properties. During the years ended December 31, 2015 , 2014 and 2013 , we capitalized $10.6 million , $15.8 million and $18.2 million , respectively. The capitalized amounts include $3.4 million , $5.5 million and $7.3 million of share-based compensation for the years ended December 31, 2015 , 2014 and 2013 , respectively. Overhead reimbursement fees We have classified fees from overhead charges billed to working interest owners of $13.1 million , $13.5 million and $10.5 million for the years ended December 31, 2015 , 2014 and 2013 , respectively, as a reduction of general and administrative expenses in the accompanying Consolidated Statements of Operations. We classified our share of these charges as oil and natural gas production costs in the amount of $5.7 million , $6.4 million and $5.8 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. In addition, we have agreements with BG Group that allow us to bill each other certain personnel costs and related fees incurred on behalf of the joint ventures in the East Texas, North Louisiana and Appalachia regions. In connection with the formation of Compass, we entered into an agreement to perform certain operational, managerial, and administrative services. Compass reimbursed us for costs incurred in connection with the performance of these services based on an agreed upon service fee. As a result of the Compass sale, this agreement was terminated on October 31, 2014 and we entered into a customary transition services agreement pursuant to which EXCO provided certain transition services to Compass until April 2015. For the years ended December 31, 2015 , 2014 and 2013 , general and administrative expenses were reduced by $15.9 million , $24.7 million and $26.8 million , respectively, for recoveries of fees for our personnel and services provided to our joint ventures and other partners. These recoveries are net of fees charged to us by BG Group for their personnel and services. Environmental costs Environmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by past operations are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently available facts related to each site. Income taxes Income taxes are accounted for in accordance with FASB ASC 740, Income Taxes ("ASC 740"), under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in earnings in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. Earnings per share We account for earnings per share in accordance with FASB ASC 260-10, Earnings Per Share ("ASC 260-10"). ASC 260-10 requires companies to present two calculations of earnings per share ("EPS"); basic and diluted. Basic EPS is based on the weighted average number of common shares outstanding during the period, excluding stock options, restricted share units, restricted share awards and warrants. Diluted EPS is computed in the same manner as basic EPS after assuming the issuance of common shares for all potentially dilutive common share equivalents, which include stock options, restricted share units, restricted share awards and warrants, whether exercisable or not. Our diluted EPS for the year ended December 31, 2013 also included subscription rights which were the result of the rights offering of our common shares as discussed in "Note 15. Rights Offering and other equity transactions". Equity-based compensation Our equity-based compensation includes share-based compensation to employees which we account for in accordance with FASB ASC Topic 718, Compensation-Stock Compensation ("ASC 718") and equity-based compensation for warrants issued to ESAS which we account for in accordance with FASB ASC Topic 505-50, Equity-Based Payments to Non-Employees ("ASC 505-50"). ASC 718 requires all share-based payments to employees, including grants of employee stock options, restricted share units and restricted share awards, to be recognized in our Consolidated Statements of Operations based on their estimated fair values. We recognize expense on a straight-line basis over the vesting period of the option, restricted share unit or restricted share award. We capitalize part of our share-based compensation that is attributable to our acquisition, exploration, exploitation and development activities. Our 2005 Amended and Restated Long-Term Incentive Plan ("2005 Incentive Plan") provides for the granting of options and other equity incentive awards of our common shares in accordance with terms within the agreements. New shares will be issued for any options exercised or awards granted. Under the 2005 Incentive Plan, we have only issued stock options, restricted share units and restricted share awards, although the plan allows for other share-based awards. The measurement of the warrants is accounted for in accordance with ASC 505-50, which requires the warrants to be re-measured each interim reporting period until the completion of the services under the agreement and an adjustment is recorded in our Consolidated Statements of Operations included as equity-based compensation expense. See "Note. 11. Equity-based compensation" for additional information on the warrants issued to ESAS. Recent accounting pronouncements In April 2015, the FASB issued Accounting Standards Update ("ASU") No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Prior to the adoption of ASU 2015-03, we recognized debt issuance costs as assets on our balance sheet. The recognition and measurement guidance for debt issuance costs are not affected by ASU 2015-03. ASU 2015-03 is effective for annual and interim periods beginning after December 15, 2015 and early adoption is permitted. In August 2015, the FASB issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements ("ASU 2015-15"). ASU 2015-15 clarifies that the SEC would not object to an entity deferring and presenting debt issuance costs related to a line-of-credit arrangement as an asset on the balance sheet. We adopted ASU 2015-03 and ASU 2015-15 in the fourth quarter of 2015 and applied the new guidance retrospectively to all periods presented. The adoption of ASU 2015-03 and ASU 2015-15 resulted in certain reclassifications of debt issuance costs on our balance sheets. See "Note 5. Debt" for additional information. In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments ("ASU 2015-16"). ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in this update require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in this update require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. ASU 2015-16 is effective for annual and interim periods beginning after December 15, 2015 and early adoption is permitted. We will apply this guidance to business combinations, when applicable, occurring after the effective date of ASU 2015-16. In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes ("ASU 2015-17"). Prior to ASU 2015-17, GAAP required an entity to separate deferred income tax asset and liabilities into current and noncurrent amounts on the balance sheet. ASU 2015-17 requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. ASU 2015-17 is effective for annual and interim periods beginning after December 15, 2016 and early adoption is permitted. ASU 2015-17 may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We adopted ASU 2015-17 in 2015 and applied the guidance retrospectively which resulted in the reclassification of $35.9 million of net current deferred income tax liabilities to noncurrent as of December 31, 2014. The requirement that deferred tax liabilities and assets be offset and presented as a single amount was not affected by this amendment. See "Note 12. Income taxes" for further discussion and application of ASU 2015-17 to prior period information. In February 2016, the FASB issued 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. 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. Transaction will require application of the new guidance at the beginning of the earliest comparative period presented. We are currently assessing the potential impact of ASU 2016-02 and expect it will have a material impact on our consolidated financial condition and results of operations upon adoption.

Acquisitions, Divestitures And

Acquisitions, Divestitures And Other Significant Events	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisition, Divestitures and Other Significant Events	Acquisitions, divestitures and other significant events 2015 Acquisitions Eagle Ford acquisition program We have a participation agreement with a joint venture partner for the development of certain assets in the Eagle Ford shale ("Participation Agreement"). The Participation Agreement requires us to offer to purchase our joint venture partner's working interest in wells that have been on production for at least one year . The offers are made on a quarterly basis for a group of wells based on prices defined in the Participation Agreement, subject to specific well criteria and return hurdles. We closed the first acquisition of our joint venture partner's interest in 3 gross ( 1.4 net) wells on March 11, 2015 for a total purchase price of $7.6 million . Our joint venture partner did not accept our second offer for 10 gross ( 5.2 net) wells in July 2015. The wells included in the offer did not meet the specified return hurdle in the Participation Agreement; therefore, our joint venture partner was not required to sell us the wells included in this offer. During the fourth quarter of 2015, our Eagle Ford joint venture partner purported to accept our third quarterly offer under the Participation Agreement to purchase interests in 21 gross ( 10.3 net) wells for $42.7 million , subject to purchase price adjustments subsequent to the effective date of June 30, 2015. We notified our joint venture partner that we do not intend to close this acquisition and our joint venture partner filed a petition for injunctive relief and damages alleging that, among other things, we breached our obligation under the Participation Agreement. The court denied our joint venture partner’s motion for injunctive relief and their request to restrain us from disbursing proceeds from the production of the assets. We filed a counterclaim seeking a declaratory judgment that, among other things, we are not obligated to purchase the disputed wells as our partner's purported acceptance had not been received in a timely manner under the terms of the Participation Agreement. In addition, quarterly offers four and five are also now in dispute for various reasons. We cannot estimate or predict the outcome of the litigation with the our joint venture partner and we may not have sufficient funds or borrowing capacity under the EXCO Resources Credit Agreement to complete any acquisitions pursuant to the Participation Agreement or pay any damages for failure to complete a purchase that a court may determine, including the wells related to the claim by our joint venture partner. In the event we fail to purchase a group of wells that we are required to make an offer on, there are remedies available to our joint venture partner which allow them to reject our future offers, terminate the Participation Agreement, remove EXCO as the operator or pursue other legal remedies. 2014 Divestitures Permian Basin transaction On March 24, 2014, we closed a purchase and sale agreement with a private party for the sale of our interest in certain non-operated assets in the Permian Basin including producing wells and undeveloped acreage for approximately $68.2 million , after final purchase price adjustments. The effective date of the transaction was January 1, 2014. Proceeds from the sale were used to reduce indebtedness under our credit agreement ("EXCO Resources Credit Agreement"). Compass divestiture On October 31, 2014, we closed the sale of our entire interest in Compass to Harbinger Group, Inc. ("HGI") for $118.8 million in cash. We used a portion of the proceeds to reduce indebtedness under the EXCO Resources Credit Agreement. Prior to the closing of the sale, we reported our 25.5% interest in Compass using proportional consolidation. Our consolidated assets and liabilities were reduced by our proportionate share of Compass's net assets of $31.4 million which included our proportionate share of the Compass's indebtedness of $83.2 million on October 31, 2014. The sale of our interest in Compass did not significantly alter the relationship between our capitalized costs and proved reserves and was accounted for as an adjustment of capitalized costs with no gain or loss recognized in accordance with Rule 4-10(c)(6)(i) of Regulation S-X. As a result, our capitalized costs were further reduced by $87.4 million . Following the closing, EXCO was no longer required to offer acquisition opportunities to Compass or any of its affiliates. 2013 Acquisitions, divestitures and other significant events Compass On February 14, 2013 , we formed Compass. Pursuant to the agreements governing the transaction, we contributed our conventional shallow producing assets in East Texas and North Louisiana and our shallow Canyon Sand and other assets in the Permian Basin of West Texas to Compass, in exchange for net cash proceeds of $574.8 million , after final purchase price adjustments, and a 25.5% economic interest in the partnership. HGI's economic interest in Compass was 74.5% at its formation. The contribution of oil and natural gas properties to Compass significantly altered the relationship between our capitalized costs and proved reserves. In accordance with full cost accounting rules, we recorded a gain of $186.4 million , net of a proportionate reduction in goodwill of $55.1 million , for the year ended December 31, 2013. Immediately following the closing, Compass entered into an agreement to purchase the remaining shallow Cotton Valley assets in North Louisiana from an affiliate of BG Group for $130.7 million , after final purchase price adjustments. The assets acquired as a result of this transaction represented an incremental working interest in properties owned by Compass. The transaction closed on March 5, 2013 and was funded with borrowings from Compass's credit agreement. Permian Basin transaction On March 13, 2013 , we closed a sale and joint development agreement with a private party for the sale of an undivided 50% of our interest in certain undeveloped acreage in the Permian Basin. The private party was designated as the operator under the joint development agreement. We received $37.9 million in cash, after final closing adjustments. Haynesville and Eagle Ford Acquisitions On July 2, 2013 , we entered into definitive agreements with Chesapeake to acquire producing and undeveloped oil and natural gas assets in the Haynesville and Eagle Ford shale formations. We closed the acquisition of the Haynesville assets on July 12, 2013 for a purchase price of $281.1 million , after final purchase price adjustments. The acquisition included certain producing wells and non-producing oil, natural gas and mineral leases located in our core Haynesville shale operating area in Caddo Parish and DeSoto Parish, Louisiana. These properties included Chesapeake's non-operated interests in 170 wells operated by EXCO on approximately 5,500 net acres, and operated interests in 11 producing wells on approximately 4,000 net acres. BG Group elected not to exercise its preferential right to acquire a 50% interest in these assets. We closed the acquisition of the Eagle Ford assets on July 31, 2013 for a purchase price of $661.8 million , after final purchase price adjustments. The acquisition included certain producing wells and non-producing oil, natural gas and mineral leases in the Eagle Ford shale in the counties of Zavala, Dimmit and Frio in South Texas. These properties initially included operated interests in 120 wells on approximately 53,500 net acres. In connection with the acquisition of the Eagle Ford assets, we entered into a farm-out agreement with Chesapeake covering acreage adjacent to the acquired properties. Pursuant to the terms of the farm-out agreement, Chesapeake retains an overriding royalty interest in wells drilled on acreage covered by the farm-out agreement, with an option to convert the overriding royalty interest to a working interest at payout of the well. We accounted for the acquisitions in accordance with FASB ASC Topic 805, Business Combinations . The following table presents a summary of the fair value of assets acquired and liabilities assumed as part of the Haynesville and Eagle Ford acquisitions based on the final settlement statements as of July 12, 2013 and July 31, 2013, respectively: Purchase Price Allocation (in thousands): Haynesville Acquired Properties Eagle Ford Acquired Properties Assets acquired: Unproved oil and natural gas properties $ 2,319 $ 227,869 Proved developed and undeveloped oil and natural gas properties 282,918 437,616 Liabilities assumed: Accounts payable and accrued liabilities — (580 ) Revenues and royalties payable (3,526 ) — Asset retirement obligations (610 ) (3,060 ) Total purchase price $ 281,101 $ 661,845 We performed a valuation of the assets acquired and liabilities assumed as of the respective acquisition dates. A summary of the key inputs are as follows: Oil and Natural Gas Properties - The fair value allocated to proved and unproved oil and natural gas properties was $285.2 million for the Haynesville assets and $665.5 million for the Eagle Ford assets. 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 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. Asset Retirement Obligations - The fair value allocated to asset retirement obligations was $0.6 million for the Haynesville assets and $3.1 million for the Eagle Ford assets. These asset retirement obligations represent the present value of the estimated amount to be incurred to plug, abandon and remediate our 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. Revenues and royalties payable and accounts payable and accrued liabilities - The fair value was equivalent to the carrying amount because of the short-term nature of these liabilities. KKR Participation Agreement In connection with closing the acquisition of the Eagle Ford assets, we entered into a Participation Agreement with KKR and sold an undivided 50% interest in the undeveloped acreage we acquired for approximately $130.9 million , after final purchase price adjustments. Proceeds from the sale of properties under the Participation Agreement were used to reduce outstanding borrowings under the EXCO Resources Credit Agreement. Under the Participation Agreement, EXCO is required to offer to purchase our joint venture partner's working interest in wells drilled that have been on production for approximately one year. These offers will be made on a quarterly basis for groups of wells based on a price defined in the Participation Agreement, subject to specific well criteria and return hurdles. Our joint venture partner has the right to participate in certain wells drilled in the Eagle Ford shale outside of the core area, as defined under the Participation Agreement, however these wells are not included as part of the acquisition program. If our joint venture partner elects to participate in certain wells outside of our core area, we will share equally in the working interest of the well. TGGT transaction On November 15, 2013, EXCO and BG Group closed the conveyance of 100% of the equity interests in TGGT to Azure Midstream Holdings LLC ("Azure"). We received $240.2 million in net cash proceeds at the closing and an equity interest in Azure of approximately 4% . We recorded an equity investment of $13.4 million , net of a discount for a control premium, in Azure which is accounted for under the cost method of accounting. Investments accounted for by the cost method are tested for impairment if an impairment indicator is present. During the year ended December 31, 2015, we recorded an other than temporary impairment of $2.9 million to our investment in Azure. See "Note 6. Fair value measurements" for further discussion. At the closing of the agreement, EXCO and BG Group agreed to deliver to Azure’s gathering systems an aggregate minimum volume commitment of 600,000 Mmbtu/day of natural gas production from the Holly and Shelby fields over a five year period. The minimum volume commitment may be satisfied with (i) production of EXCO, BG Group and each of their respective affiliates, (ii) production of joint venture partners of either EXCO, BG Group or their affiliates, and (iii) production of non-operating working interest owners to the extent EXCO, BG Group, and each of their respective affiliates or its joint venture partner controls such production. If there is a shortfall to the minimum volume commitment in any year, then EXCO and BG Group are severally responsible for paying to Azure a shortfall payment in an amount equal to the amount of the shortfall (calculated on an annualized basis) times $0.40 per Mmbtu. EXCO and BG Group are entitled to credit 25% of any production volumes delivered in excess of the minimum volume commitment during any year to the subsequent year. We used all of the cash proceeds from the sale of TGGT to reduce outstanding borrowings under the EXCO Resources Credit Agreement. We recorded an other than temporary impairment of $86.8 million to our investment in TGGT during 2013 as a result of the carrying value exceeding the fair value.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2015
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Derivative financial instruments	Derivative financial instruments Our primary objective in entering into derivative financial instruments is 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. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instruments. Cash losses or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respective instruments’ fair value in earnings. The table below outlines the classification of our derivative financial instruments on our Consolidated Balance Sheets and their financial impact on our Consolidated Statements of Operations. Fair Value of Derivative Financial Instruments (in thousands) December 31, 2015 December 31, 2014 Derivative financial instruments - Current assets $ 39,499 $ 97,278 Derivative financial instruments - Long-term assets 6,109 2,138 Derivative financial instruments - Current liabilities (16 ) (892 ) Derivative financial instruments - Long-term liabilities — — Net derivative financial instruments $ 45,592 $ 98,524 The Effect of Derivative Financial Instruments Year Ended December 31, (in thousands) 2015 2014 2013 Gain (loss) on derivative financial instruments $ 75,869 $ 87,665 $ (320 ) 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 includes both cash settlements and non-cash changes in fair value, are included in earnings with a corresponding increase or decrease in the Consolidated Balance Sheets fair value amounts. At December 31, 2015, our oil and natural gas derivative instruments were comprised of swap contracts which allow us to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In the fourth quarter of 2015, we settled our remaining basis swap contracts and our remaining call option contracts expired. Basis swaps allowed us to receive a fixed price differential between market indices for oil prices based on the delivery point. Our oil basis swaps typically had a positive differential to NYMEX WTI oil prices. Call options gave our trading counterparties the right, but not the obligation, to buy an agreed quantity of oil or natural gas from us at a certain time and price in the future. At the time of settlement, if the market price exceeded the fixed price of the call option, we paid the counterparty the excess. If the market price settled below the fixed price of the call option, no payment was due from either party. In exchange for selling this option, we received upfront proceeds which we used to obtain a higher fixed price on our swaps. These transactions were conducted contemporaneously with a single counterparty and resulted in a net cashless transaction. A three-way collar is a combination of options including a sold call, a purchased put and a sold put. In the fourth quarter of 2015, we converted all of our remaining 2016 three-way collars to fixed-price swaps covering 10,980 Bbtu of natural gas at an average price of $2.78 per Mmbtu. These transactions were conducted contemporaneously with the same counterparties and resulted in a net cashless transaction. We place our derivative financial instruments with the financial institutions that are lenders under our respective credit agreements that we believe have high quality credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with counterparties to our derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty. The following table presents the volumes and fair value of our oil and natural gas derivative financial instruments as of December 31, 2015 : (dollars in thousands, except prices) Volume Bbtu/Mbbl Weighted average strike price per Mmbtu/Bbl Fair value at December 31, 2015 Natural gas: Swaps: 2016 34,770 $ 3.09 $ 20,894 2017 10,950 3.28 5,279 2018 3,650 3.15 830 Total natural gas $ 27,003 Oil: Swaps: 2016 915 $ 61.89 $ 18,589 Total oil $ 18,589 Total oil and natural gas derivative financial instruments $ 45,592 At December 31, 2014 , we had outstanding swap, call option and three-way collar contracts covering 42,888 Bbtu, 20,075 Bbtu and 38,355 Bbtu, respectively, of natural gas and we had outstanding swap, basis swap and call option contracts covering 1,095 Mbbls, 91 Mbbls and 365 Mbbls, respectively, of oil. At December 31, 2015 , the average forward NYMEX WTI oil price per Bbl for the calendar year 2016 was $40.97 and the average forward NYMEX HH natural gas prices per Mmbtu for the calendar years 2016 , 2017 and 2018 were $2.50 , $2.79 and $2.91 , respectively. Our derivative financial instruments covered approximately 68% and 69% of production volumes for the years ended December 31, 2015 and 2014 .

Debt

Debt	12 Months Ended
	Dec. 31, 2015
Long-term Debt, Current and Noncurrent [Abstract]
Debt	Debt The carrying value of our total debt is summarized as follows: (in thousands) December 31, 2015 December 31, 2014 EXCO Resources Credit Agreement $ 67,492 $ 202,492 Exchange Term Loan 641,172 — Fairfax Term Loan 300,000 — 2018 Notes 158,015 750,000 Unamortized discount on 2018 Notes (932 ) (5,957 ) 2022 Notes 222,826 500,000 Deferred financing costs, net (18,294 ) (16,019 ) Total debt, net 1,370,279 1,430,516 Less amounts due within one year 50,000 — Total debt due after one year $ 1,320,279 $ 1,430,516 December 31, 2015 (in thousands) Carrying value Deferred reduction in carrying value Unamortized discount/deferred financing costs Principal balance EXCO Resources Credit Agreement $ 67,492 $ — $ — $ 67,492 Exchange Term Loan 641,172 (241,172 ) — 400,000 Fairfax Term Loan 300,000 — — 300,000 2018 Notes 157,083 — 932 158,015 2022 Notes 222,826 — — 222,826 Deferred financing costs, net (18,294 ) — 18,294 — Total debt $ 1,370,279 $ (241,172 ) $ 19,226 $ 1,148,333 Terms and conditions of each of these debt obligations are discussed below. Recent transactions On October 26, 2015, we closed a 12.5% senior secured second lien term loan with certain affiliates of Fairfax Financial Holdings Limited ("Fairfax") in the aggregate principal amount $300.0 million (“Fairfax Term Loan”). We used the proceeds from the Fairfax Term Loan to repay outstanding indebtedness under the EXCO Resources Credit Agreement. We also closed a 12.5% senior secured second lien term loan with certain unsecured noteholders in the aggregate principal amount of $291.3 million on October 26, 2015 and $108.7 million on November 4, 2015 (“Exchange Term Loan,” and together with the Fairfax Term Loan, “Second Lien Term Loans”). The proceeds from the Exchange Term Loan were used to repurchase a portion of the outstanding 7.5% senior unsecured notes due September 15, 2018 ("2018 Notes") and 8.5% senior unsecured notes due April 15, 2022 ("2022 Notes") in exchange for the holders of such notes agreeing to act as lenders in connection with the Exchange Term Loan. The exchange was accounted for as a troubled debt restructuring pursuant to FASB ASC 470-60, Troubled Debt Restructuring by Debtors . We have determined that the future undiscounted cash flows from the Exchange Term Loan through its maturity were less than the carrying amounts of the retired 2018 Notes and 2022 Notes. As a result, we have adjusted our carrying amount of the Exchange Term Loan to equal the total future cash payments, including interest and principal, which resulted in a net gain on the restructuring of debt of $165.1 million included in Gain on restructuring and extinguishment of debt in our Consolidated Statements of Operations. Subsequently, all cash payments under the terms of the Exchange Term Loan, whether designated as interest or as principal amount, will reduce the carrying amount and no interest expense will be recognized. As such, our reported interest expense will be less than the contractual payments throughout the term of the Exchange Term Loan. In the fourth quarter of 2015, we repurchased $40.8 million in principal of the 2018 Notes through open market purchases with $12.0 million in cash. The open market repurchases resulted in a $28.2 million net gain on extinguishment of debt which is included in Gain on restructuring and extinguishment of debt in our Consolidated Statements of Operations. The net gain included an acceleration of the related deferred financing costs and notes discount. Additionally, in February 2016, we repurchased $9.5 million and $39.9 million in principal of the 2018 Notes and 2022 Notes, respectively, with $6.7 million in cash. See further discussion of the Second Lien Term Loans and the 2018 Notes and 2022 Notes repurchases below. EXCO Resources Credit Agreement At December 31, 2015, the EXCO Resources Credit Agreement had $67.5 million of outstanding indebtedness, $375.0 million of available borrowing base and $300.9 million of unused borrowing base, net of letters of credit. The maturity date of the EXCO Resources Credit Agreement is July 31, 2018 . The interest rate grid for the revolving commitment under the EXCO Resources Credit Agreement ranges from LIBOR plus 225 bps to 325 bps (or alternate base rate ("ABR") plus 125 bps to 225 bps), depending on our borrowing base usage. On December 31, 2015, our interest rate was approximately 3.3% on the revolving commitment. As of December 31, 2015 , we were in compliance with the financial covenants (each as defined in the EXCO Resources Credit Agreement), which required that we: • maintain a consolidated current ratio of at least 1.0 to 1.0 as of the end of any fiscal quarter; • maintain a ratio of consolidated EBITDAX to consolidated interest expense ("Interest Coverage Ratio") of at least 1.25 to 1.0 as of the end of any fiscal quarter. The consolidated interest expense utilized in the Interest Coverage Ratio is calculated in accordance with GAAP; therefore, this excludes cash payments under the terms of the Exchange Term Loan, whether designated as interest or as face amount, that reduce the carrying amount and are not recognized as interest expense; and • not permit our ratio of senior secured indebtedness to consolidated EBITDAX ("Senior Secured Indebtedness Ratio"), to be greater than 2.5 to 1.0 as of the end of any fiscal quarter. Senior secured indebtedness utilized in the Senior Secured Indebtedness Ratio excludes the Second Lien Term Loans and any other indebtedness subordinated to the EXCO Resources Credit Agreement. On October 19, 2015, we entered into an amendment to the EXCO Resources Credit Agreement that, among other things, reduced the borrowing base from $600.0 million to $375.0 million , effective upon the issuance of the Second Lien Term Loans. The amendment also amended the EXCO Resources Credit Agreement such that, upon our incurrence of second or third lien debt, including the Second Lien Term Loans, the revolving commitments under the EXCO Resources Credit Agreement were automatically reduced to $375.0 million . The Second Lien Term Loans limit the issuance of priority lien indebtedness to a maximum of $500.0 million without prior written consent of the administrative agent of the Fairfax Term Loan. In addition, the amendment provides that, with respect to the issuance of any second or third lien debt following the incurrence of the Second Lien Loans, if the issuance of such debt causes the aggregate principal amount of our second or third lien debt to exceed $900.0 million , the borrowing base will be further reduced. The requirement to comply with the leverage ratio maintenance covenant (as defined in the EXCO Resources Credit Agreement) was terminated as a result of the amendment. The borrowing base under the EXCO Resources Credit Agreement remains subject to semi-annual review and redetermination by the lenders pursuant to the terms of the EXCO Resources Credit Agreement, and the next scheduled redetermination of the borrowing base is set to occur in March 2016. The majority of our subsidiaries are guarantors under the EXCO Resources Credit Agreement. The EXCO Resources Credit Agreement permits investments, loans and advances to the unrestricted subsidiaries related to our joint ventures with certain limitations, and allows us to repurchase up to $200.0 million of our common shares, of which $7.6 million has been repurchased to date. The 16,621 shares and 38,821 shares repurchased in 2015 and 2014, respectively, were tendered by employees to satisfy minimum tax withholding amounts for restricted share awards. Borrowings under the EXCO Resources Credit Agreement are collateralized by first lien mortgages providing a security interest of not less than 80% of the engineered value, as defined in the agreement, in our oil and natural gas properties covered by the borrowing base. We are permitted to have derivative financial instruments covering no more than 100% of forecasted production from total Proved Reserves, as defined in the agreement, for any month during the first two years of the forthcoming five-year period, 90% of forecasted production from total Proved Reserves for any month during the third year of the forthcoming five-year period and 85% of forecasted production from total Proved Reserves for any month during the fourth and fifth years of the forthcoming five-year period. Second Lien Term Loans Each of the Second Lien Term Loans matures on October 26, 2020 and bears interest at a rate of 12.5% per annum, which is payable on the last day in each calendar quarter. The Second Lien Term Loans are guaranteed by substantially all of EXCO’s subsidiaries, with the exception of certain non-guarantor subsidiaries and our jointly-held equity investments with BG Group, and are secured by second-priority liens on substantially all of EXCO’s assets securing the indebtedness under the EXCO Resources Credit Agreement. The Second Lien Term Loans rank (i) junior to the debt under the EXCO Resources Credit Agreement and any other priority lien obligations, (ii) pari passu to one another and (iii) effectively senior to all of our existing and future unsecured senior indebtedness, including the 2018 Notes and the 2022 Notes, to the extent of the collateral. The agreements governing the Second Lien Term Loans contain covenants that, subject to certain exceptions, limit our ability and the ability of our restricted subsidiaries to, among other things: • pay dividends or make other distributions or redeem or repurchase our common shares; • prepay, redeem or repurchase certain debt; • enter into agreements restricting the subsidiary guarantors’ ability to pay dividends to us or another subsidiary guarantor, make loans or advances to us or transfer assets to us; • engage in asset sales or substantially alter the business that the we conduct; • enter into transactions with affiliates; • consolidate, merge or dispose of assets; • incur liens; and • enter into sale/leaseback transactions. In addition, the term loan agreement governing the Exchange Term Loan prohibits us from incurring, among other things and subject to certain exceptions: • debt under the EXCO Resources Credit Agreement in excess of the greatest of (i) $375.0 million plus an amount equal to six and two-thirds percent of the aggregate principal amount of our outstanding indebtedness under the EXCO Resources Credit Agreement for over-advances to protect collateral, (ii) the borrowing base under the EXCO Resources Credit Agreement or (iii) 30% of modified adjusted consolidated net tangible assets (as defined in the agreement); • second lien debt in excess of $700.0 million ; and • unsecured debt where on the date of such incurrence or after giving effect to such incurrence, our consolidated coverage ratio (as defined in the agreement) is or would be less than 2.25 to 1.0. The term loan agreement governing the Fairfax Term Loan prohibits us from incurring, among other things and subject to certain exceptions: • debt under the EXCO Resources Credit Agreement in excess of $375.0 million plus an amount equal to six and two-thirds percent of the aggregate principal amount of our outstanding indebtedness under the EXCO Resources Credit Agreement for over-advances to protect collateral, provided that such indebtedness may not exceed $500.0 million , unless we obtain consent from the administrative agent; • second lien debt, other than the Exchange Term Loan, in excess of (i) $400.0 million prior to December 31, 2015 and(ii) an amount to be agreed upon with the administrative agent after December 31, 2015; • junior lien debt, unless such debt is being used to refinance the 2018 Notes or the 2022 Notes or the terms and conditions of such junior lien debt are approved by the administrative agent; and • unsecured debt, unless we obtain consent from the administrative agent. In connection with the Second Lien Term Loans, on October 26, 2015, EXCO entered into an intercreditor agreement governing the relationship between EXCO’s lenders and the holders of any other lien obligations that EXCO may issue in the future and a collateral trust agreement governing the administration and maintenance of the collateral securing the Second Lien Term Loans. 2018 Notes The 2018 Notes are guaranteed on a senior unsecured basis by a majority of EXCO’s subsidiaries, with the exception of certain non-guarantor subsidiaries and our jointly-held equity investments with BG Group. Our equity investments with BG Group, other than OPCO, have been designated as unrestricted subsidiaries under the indenture governing the 2018 Notes. In the fourth quarter of 2015, EXCO repurchased an aggregate $551.2 million of the 2018 Notes in exchange for certain holders of the 2018 Notes to act as lenders under the Exchange Term Loan. Additionally, we repurchased $40.8 million in principal amount of the 2018 Notes with $12.0 million in cash through open market purchases in the fourth quarter of 2015. Additionally, in February 2016, we repurchased $9.5 million in principal amount of the 2018 Notes with $2.2 million in cash. The 2018 Notes repurchased will be canceled by the trustee following customary settlement procedures. As a result of the repurchases, the aggregate principal amount of outstanding 2018 Notes was reduced to $148.5 million as of February 25, 2016 . Interest accrues at 7.5% and is payable semi-annually in arrears on March 15th and September 15th of each year. The indenture governing the 2018 Notes contains covenants, which may limit our ability and the ability of our restricted subsidiaries to: • incur or guarantee additional debt and issue certain types of preferred shares; • pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt; • make certain investments; • create liens on our assets; • enter into sale/leaseback transactions; • create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us; • engage in transactions with our affiliates; • transfer or issue shares of stock of subsidiaries; • transfer or sell assets; and • consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries. On November 25, 2015, the Company obtained the requisite consents to amend the indenture governing the 2018 Notes. Following the receipt of the requisite consents, EXCO entered into a supplemental indenture which, among other things, eliminated the reduction in the amount of secured indebtedness permitted under the EXCO Resources Credit Agreement upon principal payments which results in a permanent reduction in borrowing capacity of EXCO. As a result, the amount of secured indebtedness permitted under the EXCO Resources Credit Agreement cannot exceed the greater of $1.2 billion or a calculation based on the value of our assets. 2022 Notes The 2022 Notes were issued at 100.0% of the principal amount and bear interest at a rate of 8.5% per annum, payable in arrears on April 15 and October 15 of each year. On November 4, 2015, EXCO completed a repurchase of $277.2 million of the 2022 Notes in exchange for certain holders of the 2022 Notes to act as lenders under the Exchange Term Loan. Additionally, in February 2016, we repurchased $39.9 million in principal amount of the 2022 Notes with $4.5 million in cash. The 2022 Notes repurchased will be canceled by the trustee following customary settlement procedures. As a result of the note repurchase, the aggregate principal amount of outstanding 2022 Notes was reduced to $182.9 million as of February 25, 2016 . The 2022 Notes rank equally in right of payment to any existing and future senior unsecured indebtedness of the Company (including the 2018 Notes) and are guaranteed on a senior unsecured basis by EXCO’s consolidated subsidiaries that are guarantors of the indebtedness under the EXCO Resources Credit Agreement. The 2022 Notes were issued under the same base indenture governing the 2018 Notes and the supplemental indenture governing the 2022 Notes contains similar covenants to those in the supplemental indenture governing the 2018 Notes. The foregoing descriptions are not complete and are qualified in their entirety by the EXCO Resources Credit Agreement, the indenture governing the 2018 Notes and 2022 Notes and the agreements governing the Second Lien Term Loans. Deferred Financing Costs In the fourth quarter of 2015, we adopted ASU 2015-03 and ASU 2015-15 and reclassified deferred financing costs related to the 2018 Notes, 2022 Notes and Second Lien Term Loans from an asset to a contra-liability account on our Consolidated Balance Sheets and reflected the change retrospectively in the table above. Deferred financing costs related to the EXCO Resources Credit Agreement will be classified as an asset as allowed by ASU 2015-15. Liquidity and covenants While we believe our existing capital resources, including our cash flow from operations and borrowing capacity under the EXCO Resources Credit Agreement, are sufficient to conduct our operations through 2016 and into 2017, there are certain risks arising from depressed oil and natural gas prices and declines in production volumes that could impact our liquidity and ability to meet debt covenants in future periods. Our ability to maintain compliance with our debt covenants may be negatively impacted when oil and/or natural gas prices remain depressed for an extended period of time. Reductions in our borrowing capacity as a result of a redetermination to our borrowing base could have an impact on our capital resources and liquidity. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by further declines in oil and natural gas prices. Accordingly, our ability to effectively execute our corporate strategies and manage our operating, general and administrative expenses and capital expenditure programs is critical to our financial condition, liquidity and our results of operations. If we are not able to meet our debt covenants in future periods, or if our borrowing base is significantly reduced, we may be required but unable to refinance all or part of our existing debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all, and may be required to surrender assets pursuant to the security provisions of the EXCO Resources Credit Agreement and the Second Lien Term Loans. Further, failing to comply with the financial and other restrictive covenants in the EXCO Resources Credit Agreement, 2018 Notes, 2022 Notes and the Second Lien Term Loans could result in an event of default, which could adversely affect our business, financial condition and results of operations.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
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. Fair value of derivative financial instruments The fair value of our derivative financial instruments may be different from the settlement value based on company-specific inputs, such as credit rating, futures markets and forward curves, and readily available buyers or sellers. During the years ended December 31, 2015 and 2014 there were no changes in the fair value level classifications. The following table presents a summary of the estimated fair value of our derivative financial instruments as of December 31, 2015 and 2014 . December 31, 2015 (in thousands) Level 1 Level 2 Level 3 Total Oil and natural gas derivative financial instruments $ — $ 45,592 $ — $ 45,592 December 31, 2014 (in thousands) Level 1 Level 2 Level 3 Total Oil and natural gas derivative financial instruments $ — $ 98,524 $ — $ 98,524 We evaluate derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them on a gross basis on our Consolidated Balance Sheets. Net derivative asset values are determined primarily by quoted futures prices and utilization of the counterparties’ credit-adjusted risk-free rate curves and net 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 London Interbank Offered Rate ("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 valuation of our commodity price derivatives, represented by oil and natural gas swaps, basis swaps, call option and three-way collar contracts, is discussed below. Oil derivatives. Our oil derivatives historically consisted of swap, basis swap and call option contracts for notional Bbls of oil at fixed (in the case of swap and basis swap contracts) or interval (in the case of call option contracts) NYMEX oil index prices. The asset and liability values attributable to our oil derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for oil index prices, (iii) the applicable credit-adjusted risk-free rate curve, as described above, and (iv) the implied rate of volatility inherent in the call option contracts. The implied rates of volatility were determined based on average NYMEX oil index prices. Natural gas derivatives . Our natural gas derivatives historically consisted of swap, three-way collar and call option contracts for notional Mmbtus of natural gas at posted price indexes, including NYMEX HH swap and option contracts. The asset and liability values attributable to our natural gas derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH for natural gas swaps, (iii) the applicable credit-adjusted risk-free rate curve, as described above and (iv) the implied rate of volatility inherent in the option contracts. The implied rates of volatility were determined based on average HH natural gas prices. See further details on the fair value of our derivative financial instruments in “Note 4. 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 revolving commitment of the EXCO Resources Credit Agreement approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to us for those periods. The estimated fair values of our 2018 Notes, 2022 Notes, Exchange Term Loan and Fairfax Term Loan 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 values of the Exchange Term Loan and the Fairfax Term Loan have been calculated based on quoted prices obtained from third-party pricing sources and are classified as Level 2. December 31, 2015 (in thousands) Level 1 Level 2 Level 3 Total 2018 Notes $ 43,170 $ — $ — $ 43,170 2022 Notes 48,376 — — 48,376 Exchange Term Loan — 278,000 — 278,000 Fairfax Term Loan — 208,500 — 208,500 December 31, 2014 (in thousands) Level 1 Level 2 Level 3 Total 2018 Notes $ 558,750 $ — $ — $ 558,750 2022 Notes 373,500 — — 373,500 As of February 25, 2016, the estimated fair values of our 2018 Notes, 2022 Notes, Exchange Term Loan and Fairfax Term Loan decreased to $25.2 million , $37.6 million , $178.0 million and $133.5 million , respectively. The estimated fair values were calculated based on the aggregate outstanding principal balance for each respective instrument at December 31, 2015. Other fair value measurements As discussed in "Note 2. Summary of significant accounting policies", we assess our unproved oil and natural gas properties for potential impairment due to an other than temporary trend that would negatively impact the fair value. The continued depressed oil and natural gas prices as well as longer-term commodity price outlooks provided indications of possible impairment. During the year ended December 31, 2015 , we impaired approximately $88.1 million of unproved properties to reduce the carrying value to the fair value. These impairment charges were transferred to the depletable portion of the full cost pool. We calculated the estimated fair value of our unproved properties based on the average cost per undeveloped acre or the discounted cash flow models from our internally generated oil and natural gas reserves as of December 31, 2015 . The pricing utilized in the discounted cash flow models was based on NYMEX futures, adjusted for basis differentials. Our oil and natural gas properties were further discounted based on the classification of the underlying reserves and management's assessment of recoverability. The fair value measurements utilized include significant unobservable inputs that are considered to be Level 3 within the fair value hierarchy. These unobservable inputs include management's estimates of reserve quantities, commodity prices, operating costs, development costs, discount factors and other risk factors applied to the future cash flows. The average cost per undeveloped acre was based on recent comparable market transactions in each region. We impaired $11.0 million of our equity method investment in a midstream company in the Appalachia region. The impairment was primarily a result of limited development activity in the region, which is expected to reduce the future cash flows associated with the gathering and transportation revenues of the entity. In addition, we impaired $2.9 million of our investment in a midstream company in the East Texas and North Louisiana regions that we account for under the cost method of accounting. Both of the impairments were recorded to reduce the carrying value to the fair value and are considered to be Level 3 within the fair value hierarchy. The estimated fair value of our equity method investment was determined based on trading metrics for peer companies and the discounted cash flow models from our internally generated oil and natural gas reserves for the related properties as of December 31, 2015. The estimated fair value of our cost method investment was determined based on trading metrics for peer companies.

Environmental Regulation

Environmental Regulation	12 Months Ended
	Dec. 31, 2015
Applicability, Impact and Conclusion of Environmental Loss Contingencies [Abstract]
Environmental regulation	Environmental regulation Various federal, state and local laws and regulations covering discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect our operations and the costs of our oil and natural gas exploitation, development and production operations. We do not anticipate that we will be required in the foreseeable future to expend amounts material in relation to the financial statements taken as a whole by reason of environmental laws and regulations. Because these laws and regulations are constantly being changed, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us.

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and contingencies	Commitments and contingencies The following table presents our future minimum obligations under our commercial commitments as of December 31, 2015 . The commitments do not include those of our equity method investments. (in thousands) Gathering and firm transportation services Other fixed commitments Drilling contracts Operating leases and other Total 2016 $ 120,414 $ 13,253 $ 14,997 $ 5,456 $ 154,120 2017 120,085 5,443 7,284 4,228 137,040 2018 116,365 3,210 — 3,240 122,815 2019 76,285 2,403 — 3,053 81,741 2020 48,148 1,932 — 1,560 51,640 Thereafter 135,943 1,599 — 72 137,614 Total $ 617,240 $ 27,840 $ 22,281 $ 17,609 $ 684,970 We have entered into firm transportation and gathering agreements with pipeline companies to facilitate sales from our East Texas and North Louisiana production. Gathering and firm transportation services presented in the tables within this footnote represent our gross commitments under these contracts and a portion of these costs will be incurred by working interest and other owners. We report these costs as gathering and transportation expenses or as a reduction in total sales price received from the purchaser. In addition, our variable rate firm transportation contracts do not have a minimum volume commitment and are not included in the table above. As such, our gathering and firm transportation services presented in the table above may not be representative of the amounts reported as gathering and transportation expenses in our Consolidated Financial Statements. We lease our offices and certain equipment. Our rental expenses were approximately $3.4 million , $5.1 million and $5.9 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. We have also entered into drilling rig contracts primarily to develop our assets in the East Texas and North Louisiana regions. The actual drilling costs under these contracts will be incurred by working interest owners in the development of the related properties. These contracts are short-term in nature and are dependent on our planned drilling program. Our other fixed commitments primarily consist of completion service contracts and marketing contracts in which we are obligated to pay the buyer a fee if we fail to deliver minimum quantities of natural gas. At December 31, 2015 , our firm transportation and gathering agreements covered the following gross volumes of natural gas: (in Bcf) Firm transportation services Gathering services 2016 270 110 2017 269 110 2018 269 100 2019 269 — 2020 177 — Thereafter 596 — Total 1,850 320 In the ordinary course of business, we are periodically a party to lawsuits. From time to time, oil and natural gas producers, including EXCO, have been named in various lawsuits alleging underpayment of royalties and the allocation of production costs in connection with oil and natural gas sold. We have reserved our estimated exposure and do not believe it was material to our current, or future, financial position or results of operations. We believe that we have properly reflected any potential exposure in our financial position when determined to be both probable and estimable. See further discussion of the litigation related to the Participation Agreement as part of "Item 1A. Risk Factors", "Item 3. Legal Proceedings" and "Item 7. Management's Discussion and Analysis".

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2015
General Discussion of Pension and Other Postretirement Benefits [Abstract]
Employee benefit plans	Employee benefit plans We sponsor a 401(k) plan for our employees and matched 100% of employee contributions. Our matching contributions were $5.2 million , $7.1 million and $8.8 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. We suspended our employer matching program for 2016 in response to depressed oil and natural gas prices.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings per share	Earnings per share The following table presents the basic and diluted earnings (loss) per share computations for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, (in thousands, except per share data) 2015 2014 2013 Basic net income (loss) per common share: Net income (loss) $ (1,192,381 ) $ 120,669 $ 22,204 Weighted average common shares outstanding 273,621 268,258 215,011 Net income (loss) per basic common share $ (4.36 ) $ 0.45 $ 0.10 Diluted net income (loss) per common share: Net income (loss) $ (1,192,381 ) $ 120,669 $ 22,204 Weighted average common shares outstanding 273,621 268,258 215,011 Dilutive effect of: Stock options — — — Restricted shares and restricted share units — 118 420 Warrants — — — Subscription rights — — 15,481 Weighted average common shares and common share equivalents outstanding 273,621 268,376 230,912 Net income (loss) per diluted common share $ (4.36 ) $ 0.45 $ 0.10 The computation of diluted EPS excluded 39,544,192 , 14,316,409 and 55,524,191 antidilutive common share equivalents for the years ended December 31, 2015 , 2014 and 2013 , respectively.

Equity-based compensation

Equity-based compensation	12 Months Ended
	Dec. 31, 2015
Share-based Compensation [Abstract]
Equity-based compensation	Stock options and awards Description of plan Our 2005 Incentive Plan is a shareholder-approved plan authorizing the issuance of up to 45,500,000 restricted shares, restricted share units and stock options. As of December 31, 2015 and 2014 , there were 17,773,172 and 19,763,916 shares, respectively, available for issuance under the 2005 Incentive Plan. Option grants count as one share against the total number of shares we have available for grant and restricted share grants count as 1.17 shares for awards granted before October 6, 2011, 2.1 shares for awards granted after October 6, 2011 and 1.74 shares for awards granted after June 11, 2013. The holders of restricted shares, excluding certain market-based restricted share awards discussed below, have voting rights, and upon vesting, the right to receive all accrued and unpaid dividends. Stock options Our outstanding stock option expiration dates range from 5 to 10 years following the date of grant and have a weighted average remaining life of 3.4 years. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of the grant. The following table summarizes stock option activity related to our employees under the 2005 Incentive Plan for the years ended December 31, 2015 , 2014 and 2013 : Stock Options Weighted average exercise price per share Weighted average remaining terms (in years) Aggregate intrinsic value Options outstanding at December 31, 2012 14,015,795 $ 13.20 Granted 2,886,500 7.48 Forfeitures (4,969,877 ) 11.32 Exercised (220,675 ) 7.66 Options outstanding at December 31, 2013 11,711,743 12.69 Granted 141,525 5.24 Forfeitures (1,700,250 ) 12.71 Exercised (2,500 ) 5.22 Options outstanding at December 31, 2014 10,150,518 12.58 Granted — — Forfeitures (4,538,858 ) 12.30 Exercised — — Options outstanding at December 31, 2015 5,611,660 $ 12.81 3.4 $ — Options exercisable at December 31, 2015 5,276,336 $ 13.18 3.2 $ — The weighted average fair value of stock options on the date of the grant during the years ended December 31, 2014 and 2013 was $2.23 and $3.53 , respectively. The total intrinsic value of stock options exercised for the years ended December 31, 2014 and 2013 was $0.0 million and $0.2 million , respectively. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. The exercise price of the options is based on the fair market value of the common shares on the date of grant. No options were granted during 2015. The following assumptions were used for the options included in the table above, for the years ended December 31: 2014 2013 Expected life 7.5 years 3.8 to 7.5 years Risk-free rate of return 2.25 - 2.61 % 0.48 - 2.49 % Volatility 59.46 - 59.61 % 49.47 - 59.86 % Dividend yield 3.36 - 4.34 % 2.27 - 3.87 % Expected life was determined based on EXCO's exercise history. Risk-free rate of return is a rate of a similar term U.S. Treasury zero coupon bond. Volatility was determined based on the weighted average of historical volatility of our common shares and the daily closing prices from comparable public companies. Dividend yield was determined based on EXCO's expected annual dividend and the market price of our common stock on the date of grant. Service-based restricted share awards Our service-based restricted share awards are valued at the closing price of our common shares on the date of grant and vest over a range of two to five years. A summary of our service-based restricted share activity for the years ended December 31, 2015 , 2014 and 2013 are as follows: Shares Weighted average grant date fair value per share Non-vested shares outstanding at December 31, 2012 2,806,365 $ 10.16 Granted 556,700 7.15 Vested (832,706 ) 10.47 Forfeited (602,045 ) 9.84 Non-vested shares outstanding at December 31, 2013 1,928,314 $ 9.26 Granted 1,339,782 5.20 Vested (1,109,866 ) 9.79 Forfeited (280,301 ) 6.89 Non-vested shares outstanding at December 31, 2014 1,877,929 $ 6.40 Granted 4,414,470 1.05 Vested (847,446 ) 6.80 Forfeited (903,383 ) 3.17 Non-vested shares outstanding at December 31, 2015 4,541,570 $ 1.77 Market-based restricted share awards On August 13, 2013, EXCO’s officers were granted a market-based restricted share award with vesting dependent on the Company's common share price achieving certain price targets. There were 290,200 shares outstanding on December 31, 2015, including 145,100 shares that will be vested following any 30 consecutive trading days in which the company’s common stock equals or exceeds $10.00 per share and 145,100 shares will be vested following any 30 consecutive trading days in which the Company’s common shares equals or exceeds $15.00 per share ("Target Price Awards"). The shares expire on August 13, 2018 and are subject to vesting provisions depending on when the target price attainment date occurs. No such awards were granted in 2015 or 2014 and no awards have vested to date. On July 1, 2014, EXCO's officers were granted restricted share units ("RSU") which have a vesting percentage between 0% and 200% depending on EXCO's total shareholder return in comparison to an identified peer group. These units will vest on the third anniversary of the date of grant, subject to the achievement of certain criteria. Total compensation expense will be recognized over the vesting period using the straight-line method. No such awards were granted in 2015. The grant date fair values of our market-based restricted share awards and restricted share units were determined using a Monte Carlo model which uses company-specific inputs to generate different stock price paths. A summary of our market-based restricted share activity for the years ended December 31, 2015 and 2014 is as follows: Target Price Awards RSUs Shares Weighted average grant date fair value per share Shares Weighted average grant date fair value per share Non-vested shares/units outstanding at December 31, 2014 401,400 $ 6.36 716,150 $ 7.33 Granted — — — — Vested — — — — Forfeited (111,200 ) 6.36 (169,272 ) 7.33 Non-vested shares/units outstanding at December 31, 2015 290,200 $ 6.36 546,878 $ 7.33 Liability-classified awards On July 1, 2015, EXCO’s officers were granted 2,496,250 performance-based share units ("PSU") as a part of its equity compensation program. Each participant is eligible to vest in and receive a number of PSUs, ranging from 0% to 200% of the target number of PSUs granted, based on the attainment of total shareholder return goals on the period commencing on and including the date of grant and ending on the third anniversary of the grant date. Each PSU represents a non-equity unit with a conversion value equal to the fair market value of a share of EXCO’s common stock. Under the terms of the agreements, the Company is required to convert vested PSUs into a cash payment in an aggregate amount equal to the number of vested PSUs multiplied by the fair market value of a share of common stock as of the vesting date, less applicable withholdings and deductions, as soon as administratively practicable following the determination that the vesting conditions have been achieved. A summary of the PSUs for the years ended December 31, 2015 is as follows: Shares Weighted average fair value per share Non-vested units outstanding at December 31, 2014 — $ — Granted 2,496,250 1.45 Vested — — Forfeited (381,250 ) 1.25 Non-vested units outstanding at December 31, 2015 2,115,000 $ 2.39 The PSUs are considered liability-classified awards because of the cash-settlement feature. At December 31, 2015, we recorded a liability of $0.6 million related to the PSUs included in the Asset retirement obligations and other long-term liabilities line item on our Consolidated Balance Sheets. Compensation costs associated with the PSUs are re-measured each interim reporting period and an adjustment is recorded in General and administrative expenses line item in our Consolidated Statements of Operations. The fair values of the PSUs were determined using a Monte Carlo model. The ranges for the assumptions used in the Monte Carlo model for the PSUs during 2015 are as follows: Assumption Range during 2015 Risk-free rate of return 0.85 - 1.18 % Volatility 62.58 - 95.79 % Dividend yield 0.00 - 0.00 % Warrants On September 8, 2015, EXCO issued warrants to ESAS in four tranches to purchase an aggregate of 80,000,000 common shares. The warrants were issued as an additional performance incentive under the services and investment agreement which is described in more detail in "Note. 13. Related party transactions". The table below lists the number of common shares issuable upon exercise of the warrants at each exercise price and the term of the warrants. Tranche Number of shares issuable Exercise Price Term Tranche A 15,000,000 $2.75 April 30, 2019 Tranche B 20,000,000 $4.00 March 31, 2020 Tranche C 20,000,000 $7.00 March 31, 2021 Tranche D 25,000,000 $10.00 March 31, 2021 The warrants will vest on March 31, 2019 and their exercisability is subject to EXCO’s common share price achieving certain performance hurdles as compared to the peer group. If EXCO’s performance rank is in the bottom half of the peer group, then the warrants will be forfeited and void. The number of the exercisable shares under the warrants increases linearly from 32,000,000 to 80,000,000 as EXCO’s performance rank increases from the 50th to 75th percentile, as compared to the peer group. If EXCO’s performance rank is in the 75th percentile or above, then all 80,000,000 warrants will be exercisable. The performance measurement period began on March 31, 2015 and will end on March 31, 2019. As of December 31, 2015, EXCO's performance rank during the measurement period was above the 75th percentile of the peer group. Prior to March 31, 2019, if EXCO terminates the agreement for any reason other than for cause (as defined in the agreement), or ESAS terminates the agreement for cause (as defined in the agreement), then all of the warrants will fully vest and become exercisable. Prior to March 31, 2019, if ESAS terminates the agreement for any reason other than for cause, or EXCO terminates the agreement for cause, then each of the warrants will be canceled and forfeited. On August 18, 2015, EXCO’s shareholders approved, among other things, the increase to the authorized number of common shares available for issuance to 780,000,000 which ensures that an adequate number of common shares are available for issuance, including the shares to be reserved for issuance under the warrants issued to ESAS. In accordance with FASB ASC Topic 718, Compensation - Stock Compensation ("ASC 718"), the grant date of the warrants was established upon approval of EXCO’s shareholders and the closing of the services and investment agreement which occurred on September 8, 2015. The fair value of the warrants is dependent on factors such as our share price, historical volatility, risk-free rate and performance relative to our peer group and is determined using a Monte Carlo model. The table below shows the aggregate estimated fair value of the warrants as of December 31, 2015: Tranche Number of shares issuable Estimated fair value per warrant Estimated fair value (in millions) Tranche A 15,000,000 $0.50 $7.5 Tranche B 20,000,000 $0.50 10.0 Tranche C 20,000,000 $0.48 9.6 Tranche D 25,000,000 $0.40 10.0 $37.1 Compensation costs All of our stock options, restricted shares and PSUs are accounted for in accordance with ASC 718 and are classified as equity except for the PSUs. As required by ASC 718, the granting of options and awards to our employees under the 2005 Incentive Plan are share-based payment transactions and are to be treated as compensation expense by us with a corresponding increase to additional paid-in capital. Total share-based compensation to employees to be recognized on unvested options, restricted share awards and RSUs as of December 31, 2015 was $7.9 million and will be recognized over a weighted average period of 1.9 years. The measurement of the warrants is accounted for in accordance with ASC Topic 505-50, Equity-Based Payments to Non-Employees , which requires the warrants to be re-measured each interim reporting period until the completion of the services under the agreement and an adjustment is recorded in the statement of operations within equity-based compensation expense. For the year ended December 31, 2015, we recognized equity-based compensation related to the warrants of $3.2 million . The following is a reconciliation of our compensation expense for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, (in thousands) 2015 2014 2013 Equity-based compensation expense (1) $ 7,198 $ 4,962 $ 10,748 Equity-based compensation capitalized 3,428 5,498 7,288 Total equity-based compensation $ 10,626 $ 10,460 $ 18,036 Compensation expense on liability-classified awards (2) $ 396 $ — $ — (1) Equity-based compensation expense includes share-based compensation to employees and equity-based compensation for warrants issued to ESAS in 2015. (2) Compensation expense on liability-classified awards is net of compensation capitalized of $0.2 million . We did not recognize a tax benefit attributable to our equity-based compensation for the years ended December 31, 2015, 2014 and 2013.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Accrued Income Taxes [Abstract]
Income taxes	Income taxes The income tax provision attributable to our income (loss) before income taxes for the years ended December 31, 2015 , 2014 and 2013 , consisted of the following: Year ended December 31, (in thousands) 2015 2014 2013 Current: Federal $ — $ — $ — State — — — Total current income tax (benefit) $ — $ — $ — Deferred: Federal $ (414,834 ) $ 45,797 $ 25,626 State (45,009 ) 18,960 3,239 Valuation allowance 459,843 (64,757 ) (28,865 ) Total deferred income tax (benefit) — — — Total income tax (benefit) $ — $ — $ — We have net operating loss carryforwards ("NOLs") for United States income tax purposes that have been generated from our operations. Our NOLs are scheduled to expire if not utilized between 2028 and 2034. As a result of the repurchase of a portion of our senior unsecured notes during 2015, we had cancellation of debt income for tax purposes. We reduced our NOLs, including the entire tax net operating loss for year ended December 31, 2015, by the amount of cancellation of debt income of approximately $538.0 million . NOLs and alternative minimum tax credits available for utilization as of December 31, 2015 were approximately $1.8 billion and $1.5 million , respectively. We generated a net capital loss of approximately $105.6 million during the year ended December 31, 2014 as a result of the sale of our interest in Compass. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. We adopted ASU 2015-17 in the fourth quarter of 2015 and applied the guidance retrospectively which resulted in the reclassification of $35.9 million of net current deferred income tax liabilities to non-current as of December 31, 2014. See "Note 2. Summary of significant accounting policies" for description of ASU 2015-17. Significant components of our deferred tax liabilities and assets are as follows: (in thousands) December 31, 2015 December 31, 2014 Non-current deferred tax assets: Net operating loss and AMT credits carryforwards $ 689,441 $ 781,899 Capital loss carryforwards 40,356 40,356 Equity-based compensation 17,372 14,856 Oil and natural gas properties, gathering assets, and equipment 356,471 — Debt restructuring 122,900 — Goodwill 1,308 5,419 Investment in partnerships 76,099 72,988 Other 3,387 2,668 Total non-current deferred tax assets 1,307,334 918,186 Valuation allowance (1,286,695 ) (826,852 ) Total non-current deferred tax assets 20,639 91,334 Non-current deferred tax liabilities: Oil and natural gas properties, gathering assets, and equipment $ — $ (51,961 ) Derivative financial instruments (20,639 ) (39,373 ) Total non-current deferred tax liabilities (20,639 ) (91,334 ) Net non-current deferred tax assets (liabilities) $ — $ — A reconciliation of our income tax provision (benefit) computed by applying the statutory United States federal income tax rate to our income (loss) before income taxes for the years ended December 31, 2015 , 2014 and 2013 is presented in the following table: Year Ended December 31, (in thousands) 2015 2014 2013 Federal income taxes (benefit) provision at statutory rate of 35% $ (417,333 ) $ 42,234 $ 7,772 Increases (reductions) resulting from: Goodwill — — 16,382 Adjustments to the valuation allowance 459,843 (64,757 ) (28,865 ) Non-deductible compensation 2,399 3,409 1,328 State taxes net of federal benefit (45,009 ) 3,464 3,239 State tax rate change — 15,496 — Other 100 154 144 Total income tax provision $ — $ — $ — During years ended 2015, 2014 and 2013, both federal and state income tax expense or tax benefit were reduced to zero by a corresponding increase or decrease to the valuation allowance previously recognized against net deferred tax assets. The net result was no income tax provision for years ended December 31, 2015, 2014 and 2013. We adopted the provisions of ASC 740-10 on January 1, 2007. As a result of the implementation of ASC 740-10, the Company did not recognize any liabilities for unrecognized tax benefits. As of December 31, 2015 , 2014 and 2013 , the Company's policy is to recognize interest related to unrecognized tax benefits of interest expense and penalties in operating expenses. The Company has not accrued any interest or penalties relating to unrecognized tax benefits in the consolidated financial statements. We file a corporate consolidated income tax return for U.S. federal income tax purposes and file income tax return in various states. With few exceptions, we are no longer subject to U.S. federal and state and local examinations by tax authorities for years before 2006. The Company was notified during the year ended December 31, 2013 that the corporate tax return for the year ended December 31, 2011 would be examined by the Internal Revenue Service. In addition, two pass-through entities in which the Company owns an interest will also be examined for the year ended December 31, 2010. During 2014, the Internal Revenue Service completed the exam on the corporate return and on one of the two pass-through entities. No changes were made to either the corporate or partnership return as originally filed as a result of the exams. The Company was notified during 2015 that the Internal Revenue Service has completed its examination of the remaining partnership return and no changes were made to the return as originally filed.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related party transactions	Related party transactions OPCO OPCO serves as the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis. We did not advance any funds to OPCO during the years ended December 31, 2015 or 2014. OPCO may distribute any excess cash equally between us and BG Group when its operating cash flows are sufficient to meet its capital requirements. There are service agreements between us and OPCO whereby we provide administrative and technical services for which we are reimbursed. For the years ended December 31, 2015 , 2014 and 2013 these transactions included the following: Year Ended December 31, (in thousands) 2015 2014 2013 Advances to OPCO $ — $ — $ 28,378 Amounts received from OPCO 30,577 53,002 43,632 As of December 31, 2015 and 2014 , the amounts owed under the service agreements were as follows: (in thousands) December 31, 2015 December 31, 2014 Amounts due to EXCO (1) $ 1,733 $ 2,799 Amounts due from EXCO (1) 10,410 — (1) Advances to OPCO are recorded in "Inventory and other" on our Condensed Consolidated Balance Sheets. Any amounts we owe to OPCO are netted against the advance until the advances are utilized. If the advances are fully utilized, we record amounts owed in "Accounts payable and accrued liabilities" on our Condensed Consolidated Balance Sheets. Services and investment agreement On March 31, 2015, we entered into a four year services and investment agreement with ESAS, a wholly-owned subsidiary of Bluescape Resources Company LLC ("Bluescape"). As part of this agreement, ESAS provides us with certain strategic advisory services, including the development and execution of a strategic improvement plan. On September 8, 2015 we closed the services and investment agreement with ESAS and C. John Wilder, Executive Chairman of Bluescape, was appointed as a member of our Board of Directors and as Executive Chairman of the Board of Directors. On September 8, 2015, ESAS completed the purchase of 5,882,353 common shares from EXCO, par value $0.001 per share, at a price per share of $1.70 , pursuant to the agreement. In addition, the services and investment agreement was amended to reduce the additional amount of common shares to at least $13.5 million that ESAS is obligated to purchase through open market purchases. ESAS completed the required investment on December 31, 2015 by purchasing a total 12,464,130 common shares during the fourth quarter of 2015. As of December 31, 2015, ESAS owned common shares of EXCO with an aggregate cost basis of $23.5 million and is the beneficial owner of approximately 6.5% of our outstanding common shares. As consideration for the services to be provided under the agreement, EXCO will pay ESAS a monthly fee of $300,000 and an annual incentive payment of up to $2.4 million per year that will be based on EXCO’s common share price achieving certain performance hurdles as compared to a peer group, provided that payment for the services will be held in escrow and contingent upon completion of the entire first year of services and required investment in EXCO. If EXCO’s performance rank is below the 50th percentile of the peer group, then the incentive payment will be zero . The incentive payment increases linearly from $1.0 million to $2.4 million as EXCO’s performance rank increases from the 50th to 75th percentile, as compared to the peer group. If EXCO’s performance rank is in the 75th percentile or above, then the incentive payment will be $2.4 million . For the year ended December 31, 2015, we recognized $1.8 million expense for the annual incentive payment as a result of EXCO's performance rank above the 75th percentile of the peer group. As an additional performance incentive under the services and investment agreement, EXCO issued warrants to ESAS in four tranches to purchase an aggregate of 80,000,000 common shares. See "Note 11. Equity-based compensation" for further discussion of the warrants. Fairfax Term Loan Hamblin Watsa Investment Counsel Ltd. (“Hamblin Watsa”), a wholly owned subsidiary of Fairfax, is the administrative agent of the Fairfax Term Loan and certain affiliates of Fairfax are lenders under the Fairfax Term Loan. Samuel A. Mitchell, a member of our Board of Directors, is a Managing Director of Hamblin Watsa and a member of Hamblin Watsa’s investment committee, which consists of seven members that manage the investment portfolio of Fairfax. As an administrative agent of the Fairfax Term Loan, Fairfax received a one-time fee of $6.0 million from EXCO upon closing and received $6.9 million of interest payments as of December 31, 2015. At December 31, 2015, Fairfax was the beneficial owner of approximately 9.0% of our outstanding common shares. See “Note 5. Debt” for additional information. Rights offering As discussed in "Note 14. Rights offering and other equity transactions", we entered into investment agreements and closed a related private placement of our common shares with certain affiliates of WL Ross & Co. LLC ("WL Ross") and Hamblin Watsa. Wilbur L. Ross, Jr., the Chairman and Chief Executive Officer of WL Ross, and Samuel A. Mitchell, Managing Director of Hamblin Watsa, both of whom serve on EXCO's Board of Directors.

Rights Offering and other equit

Rights Offering and other equity transactions	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Rights Offering and other equity transactions	Rights Offering and other equity transactions On December 19, 2013, the Company granted subscription rights to holders of common shares which entitled the holder to purchase 0.25 of a share of our common stock for each share of common stock owned by such holders. Each subscription right entitled the holder to a basic subscription right and an over-subscription privilege. The basic subscription right entitled the holder to purchase 0.25 of a share of the Company’s common shares at a subscription price equal to $5.00 per share of common stock. The over-subscription privilege entitled the holders who exercised their basic subscription rights in full (including in respect of subscription rights purchased from others) to purchase any or all shares of our common shares that other rights holders did not purchase through the purchase of their basic subscription rights at a subscription price equal to $5.00 per share of our common shares. The subscription rights expired if they were not exercised by January 9, 2014. The Company entered into two investment agreements ("Investment Agreements") in connection with the rights offering, each dated as of December 17, 2013, one with certain affiliates of WL Ross and one with Hamblin Watsa pursuant to which, subject to the terms and conditions thereof, each of them has severally agreed to subscribe for and purchase, in a private placement, its respective pro rata portion of shares under the basic subscription right and all unsubscribed shares under the over-subscription privilege subject to pro rata allocation among the subscription rights holders who have elected to exercise their over-subscription privilege. The rights offering and related transactions under the Investment Agreements closed on January 17, 2014 ("Rights Offering") which resulted in the issuance of 54,574,734 shares for proceeds of $272.9 million . We used the proceeds to pay indebtedness under the EXCO Resources Credit Agreement. WL Ross and Hamblin Watsa purchased 19,599,973 and 6,726,712 shares, respectively, pursuant to their basic subscription rights and the over-subscription privilege. Preferred Shares We canceled all classes of our preferred shares in 2014. We have 10,000,000 preferred shares authorized with no preferred shares issued and outstanding. Our issued and outstanding shares of capital stock consist solely of common shares.

Condensed Consolidating Financi

Condensed Consolidating Financial Statements	12 Months Ended
	Dec. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed consolidating financial statements	Condensed consolidating financial statements As of December 31, 2015 , the majority of EXCO’s subsidiaries were guarantors under the EXCO Resources Credit Agreement, the indentures governing the 2018 Notes and 2022 Notes and the agreements governing the Second Lien Term Loans. All of our non-guarantor subsidiaries were considered unrestricted subsidiaries under the Second Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes, with the exception of our equity investment in OPCO. Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The 2018 Notes, 2022 Notes and the Second Lien Term Loans, 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. 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. CONDENSED CONSOLIDATING BALANCE SHEET December 31, 2015 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 34,296 $ (22,049 ) $ — $ — $ 12,247 Restricted cash 2,100 19,120 — — 21,220 Other current assets 51,133 65,201 — — 116,334 Total current assets 87,529 62,272 — — 149,801 Equity investments — — 40,797 — 40,797 Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties and development costs not being amortized — 115,377 — — 115,377 Proved developed and undeveloped oil and natural gas properties 330,775 2,739,655 — — 3,070,430 Accumulated depletion (330,775 ) (2,296,988 ) — — (2,627,763 ) Oil and natural gas properties, net — 558,044 — — 558,044 Other property and equipment, net 749 27,063 — — 27,812 Investments in and advances to affiliates, net 616,940 — — (616,940 ) — Deferred financing costs, net 8,408 — — — 8,408 Derivative financial instruments 6,109 — — — 6,109 Goodwill 13,293 149,862 — — 163,155 Total assets $ 733,028 $ 797,241 $ 40,797 $ (616,940 ) $ 954,126 Liabilities and shareholders' equity Current liabilities $ 74,472 $ 178,447 $ — $ — $ 252,919 Long-term debt 1,320,279 — — — 1,320,279 Other long-term liabilities 600 42,651 — — 43,251 Payable to parent — 2,276,594 — (2,276,594 ) — Total shareholders' equity (662,323 ) (1,700,451 ) 40,797 1,659,654 (662,323 ) Total liabilities and shareholders' equity $ 733,028 $ 797,241 $ 40,797 $ (616,940 ) $ 954,126 EXCO RESOURCES, INC. CONDENSED CONSOLIDATING BALANCE SHEET December 31, 2014 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 86,837 $ (40,532 ) $ — $ — $ 46,305 Restricted cash — 23,970 — — 23,970 Other current assets 110,145 150,346 — — 260,491 Total current assets 196,982 133,784 — — 330,766 Equity investments — — 55,985 — 55,985 Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties and development costs not being amortized — 276,025 — — 276,025 Proved developed and undeveloped oil and natural gas properties 335,838 3,516,235 — — 3,852,073 Accumulated depletion (330,771 ) (2,083,690 ) — — (2,414,461 ) Oil and natural gas properties, net 5,067 1,708,570 — — 1,713,637 Other property and equipment, net 1,269 23,375 — — 24,644 Investments in and advances to affiliates, net 1,746,931 — — (1,746,931 ) — Deferred financing costs, net 14,617 — — — 14,617 Derivative financial instruments 2,138 — — — 2,138 Goodwill 13,293 149,862 — — 163,155 Total assets $ 1,980,297 $ 2,015,591 $ 55,985 $ (1,746,931 ) $ 2,304,942 Liabilities and shareholders' equity Current liabilities $ 39,506 $ 289,930 $ — $ — $ 329,436 Long-term debt 1,430,516 — — — 1,430,516 Other long-term liabilities 271 34,715 — — 34,986 Payable to parent — 2,058,683 — (2,058,683 ) — Total shareholders' equity 510,004 (367,737 ) 55,985 311,752 510,004 Total liabilities and shareholders' equity $ 1,980,297 $ 2,015,591 $ 55,985 $ (1,746,931 ) $ 2,304,942 EXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS For the year ended December 31, 2015 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues: Oil and natural gas $ 4 $ 328,327 $ — $ — $ 328,331 Costs and expenses: Oil and natural gas production 37 76,496 — — 76,533 Gathering and transportation — 99,321 — — 99,321 Depletion, depreciation and amortization 943 214,483 — — 215,426 Impairment of oil and natural gas properties 9,316 1,206,054 — — 1,215,370 Accretion of discount on asset retirement obligations 4 2,273 — — 2,277 General and administrative (4,313 ) 63,131 — — 58,818 Other operating items 1,646 (1,185 ) — — 461 Total costs and expenses 7,633 1,660,573 — — 1,668,206 Operating loss (7,629 ) (1,332,246 ) — — (1,339,875 ) Other income (expense): Interest expense, net (106,082 ) — — — (106,082 ) Gain on derivative financial instruments 75,869 — — — 75,869 Gain on restructuring and extinguishment of debt 193,276 — — — 193,276 Other income 87 35 — — 122 Equity loss — — (15,691 ) — (15,691 ) Net loss from consolidated subsidiaries (1,347,902 ) — — 1,347,902 — Total other income (expense) (1,184,752 ) 35 (15,691 ) 1,347,902 147,494 Loss before income taxes (1,192,381 ) (1,332,211 ) (15,691 ) 1,347,902 (1,192,381 ) Income tax expense — — — — — Net loss $ (1,192,381 ) $ (1,332,211 ) $ (15,691 ) $ 1,347,902 $ (1,192,381 ) EXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS For the year ended December 31, 2014 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues: Oil and natural gas $ 3,649 $ 614,889 $ 41,731 $ — $ 660,269 Costs and expenses: Oil and natural gas production 394 77,334 16,598 — 94,326 Gathering and transportation — 97,784 3,790 — 101,574 Depletion, depreciation and amortization 3,174 244,761 15,634 — 263,569 Impairment of oil and natural gas properties — — — — — Accretion of discount on asset retirement obligations 16 2,107 567 — 2,690 General and administrative (3,342 ) 66,686 2,576 — 65,920 Other operating items (134 ) 5,459 (10 ) — 5,315 Total costs and expenses 108 494,131 39,155 — 533,394 Operating income 3,541 120,758 2,576 — 126,875 Other income (expense): Interest expense, net (92,049 ) — (2,235 ) — (94,284 ) Gain on derivative financial instruments 87,565 — 100 — 87,665 Other income 226 — 15 — 241 Equity income — — 172 — 172 Net earnings from consolidated subsidiaries 121,386 — — (121,386 ) — Total other income (expense) 117,128 — (1,948 ) (121,386 ) (6,206 ) Income before income taxes 120,669 120,758 628 (121,386 ) 120,669 Income tax expense — — — — — Net income $ 120,669 $ 120,758 $ 628 $ (121,386 ) $ 120,669 EXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS For the year ended December 31, 2013 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues: Oil and natural gas $ 9,136 $ 582,158 $ 43,015 $ — $ 634,309 Costs and expenses: Oil and natural gas production 2,440 63,716 17,092 — 83,248 Gathering and transportation — 97,166 3,479 — 100,645 Depletion, depreciation and amortization 5,917 225,499 14,359 — 245,775 Impairment of oil and natural gas properties — 108,546 — — 108,546 Accretion of discount on asset retirement obligations 63 1,881 570 — 2,514 General and administrative 23,125 66,558 2,195 — 91,878 Gain on divestitures and other operating items (25,950 ) (151,549 ) (19 ) — (177,518 ) Total costs and expenses 5,595 411,817 37,676 — 455,088 Operating income (loss) 3,541 170,341 5,339 — 179,221 Other income (expense): Interest expense, net (99,815 ) — (2,774 ) — (102,589 ) Gain (loss) on derivative financial instruments 1,439 (177 ) (1,582 ) — (320 ) Other income (loss) (1,068 ) 229 11 — (828 ) Equity loss — — (53,280 ) — (53,280 ) Net earnings from consolidated subsidiaries 118,107 — — (118,107 ) — Total other income (expense) 18,663 52 (57,625 ) (118,107 ) (157,017 ) Income (loss) before income taxes 22,204 170,393 (52,286 ) (118,107 ) 22,204 Income tax expense — — — — — Net income (loss) $ 22,204 $ 170,393 $ (52,286 ) $ (118,107 ) $ 22,204 EXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS For the year ended December 31, 2015 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Operating Activities: Net cash provided by operating activities $ 34,532 $ 99,495 $ — $ — $ 134,027 Investing Activities: Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions (2,601 ) (322,597 ) — — (325,198 ) Proceeds from disposition of property and equipment 686 6,711 — — 7,397 Restricted cash — 4,850 — — 4,850 Net changes in advances to joint ventures — 10,663 — — 10,663 Equity investments and other — 1,455 — — 1,455 Advances/investments with affiliates (217,906 ) 217,906 — — — Net cash used in investing activities (219,821 ) (81,012 ) — — (300,833 ) Financing Activities: Borrowings under credit agreements 165,000 — — — 165,000 Repayments under credit agreements (300,000 ) — — — (300,000 ) Proceeds received from issuance of Fairfax Term Loan 300,000 — — — 300,000 Repurchases of 2018 Notes (12,008 ) — — — (12,008 ) Payment on Exchange Term Loan (8,827 ) — — — (8,827 ) Proceeds from issuance of common shares, net 9,693 — — — 9,693 Payment of common share dividends (164 ) — — — (164 ) Deferred financing costs and other (20,946 ) — — — (20,946 ) Net cash provided by financing activities 132,748 — — — 132,748 Net increase (decrease) in cash (52,541 ) 18,483 — — (34,058 ) Cash at beginning of period 86,837 (40,532 ) — — 46,305 Cash at end of period $ 34,296 $ (22,049 ) $ — $ — $ 12,247 EXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS For the year ended December 31, 2014 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Operating Activities: Net cash provided by (used in) operating activities $ (84,067 ) $ 428,029 $ 18,131 $ — $ 362,093 Investing Activities: Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions (2,531 ) (395,974 ) (4,061 ) — (402,566 ) Proceeds from disposition of property and equipment 99,612 95,594 (7,551 ) — 187,655 Restricted cash — (3,400 ) — — (3,400 ) Net changes in advances to joint ventures — (5,026 ) — — (5,026 ) Distributions from Compass 5,856 — — (5,856 ) — Equity investments and other — 1,749 — — 1,749 Advances/investments with affiliates 125,612 (125,612 ) — — — Net cash provided by (used in) investing activities 228,549 (432,669 ) (11,612 ) (5,856 ) (221,588 ) Financing Activities: Borrowings under credit agreements 100,000 — — — 100,000 Repayments under credit agreements (959,874 ) — (5,096 ) — (964,970 ) Proceeds received from issuance of 2022 Notes 500,000 — — — 500,000 Proceeds from issuance of common shares, net 271,773 — — — 271,773 Payment of common share dividends (41,060 ) — — — (41,060 ) Compass cash distribution — — (5,856 ) 5,856 — Deferred financing costs and other (10,324 ) — (102 ) — (10,426 ) Net cash used in financing activities (139,485 ) — (11,054 ) 5,856 (144,683 ) Net increase (decrease) in cash 4,997 (4,640 ) (4,535 ) — (4,178 ) Cash at beginning of period 81,840 (35,892 ) 4,535 — 50,483 Cash at end of period $ 86,837 $ (40,532 ) $ — $ — $ 46,305 EXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS For the year ended December 31, 2013 (in thousands) Resources Guarantor Subsidiaries Non-guarantor subsidiaries Eliminations Consolidated Operating Activities: Net cash provided by (used in) operating activities $ (32,678 ) $ 365,770 $ 17,542 $ — $ 350,634 Investing Activities: Additions to oil and natural gas properties, gathering assets and equipment (15,767 ) (1,242,667 ) (38,818 ) — (1,297,252 ) Proceeds from disposition of property and equipment 244,500 505,128 — — 749,628 Restricted cash — 49,515 — — 49,515 Net changes in advances to joint ventures — 10,645 — — 10,645 Distributions from Compass 3,825 — — (3,825 ) — Equity investments and other (1,303 ) 236,289 — — 234,986 Advances/investments with affiliates (59,575 ) 59,575 — — — Net cash provided by (used in) investing activities 171,680 (381,515 ) (38,818 ) (3,825 ) (252,478 ) Financing Activities: Borrowings under the credit agreements 967,766 — 36,757 — 1,004,523 Repayments under the credit agreements (1,015,900 ) — (6,885 ) — (1,022,785 ) Proceeds from issuance of common shares, net 1,712 — — — 1,712 Payment of common share dividends (43,214 ) — — — (43,214 ) Compass cash distribution — — (3,825 ) 3,825 — Deferred financing costs and other (33,317 ) — (236 ) — (33,553 ) Net cash provided by (used in) financing activities (122,953 ) — 25,811 3,825 (93,317 ) Net increase (decrease) in cash 16,049 (15,745 ) 4,535 — 4,839 Cash at beginning of period 65,791 (20,147 ) — — 45,644 Cash at end of period $ 81,840 $ (35,892 ) $ 4,535 $ — $ 50,483

Quarterly Financial Data (unaud

Quarterly Financial Data (unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Quarterly financial data (unaudited)	Quarterly financial data (unaudited) The following are summarized quarterly financial data for the years ended December 31, 2015 and 2014 : Quarter (in thousands, except per share amounts) 1st 2nd 3rd 4th 2015 Oil and natural gas revenues $ 86,320 $ 93,742 $ 83,526 $ 64,743 Operating loss (1) (313,618 ) (421,465 ) (363,975 ) (240,817 ) Net loss (2) $ (318,112 ) $ (454,155 ) $ (354,519 ) $ (65,595 ) Basic loss per share: Net loss $ (1.17 ) $ (1.67 ) $ (1.30 ) $ (0.24 ) Weighted average shares 271,522 271,549 273,348 277,995 Diluted loss per share: Net loss $ (1.17 ) $ (1.67 ) $ (1.30 ) $ (0.24 ) Weighted average shares 271,522 271,549 273,348 277,995 2014 Oil and natural gas revenues $ 198,472 $ 182,966 $ 151,042 $ 127,789 Operating income 57,423 43,312 22,799 3,341 Net income (loss) $ (4,606 ) $ 2,293 $ 41,569 $ 81,413 Basic earnings (loss) per share: Net income (loss) $ (0.02 ) $ 0.01 $ 0.15 $ 0.30 Weighted average shares 260,716 270,492 270,631 271,053 Diluted earnings (loss) per share: Net income (loss) $ (0.02 ) $ 0.01 $ 0.15 $ 0.30 Weighted average shares 260,716 271,226 272,066 271,053 (1) Operating loss for the first, second, third and fourth quarter of 2015 includes $276.3 million , $394.3 million , $339.4 million and $205.3 million , respectively, of impairments of oil and natural gas properties. See "Note 2. Summary of significant accounting policies" for further discussion. (2) Net loss for the fourth quarter of 2015 includes a $193.3 million net gain on restructuring and extinguishment of debt. See "Note 5. Debt" for further discussion.

Supplemental Information Relati

Supplemental Information Relating To Oil And Natural Gas Producing Activities (unaudited)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Supplemental information relating to oil and natural gas producing activities (unaudited)	Supplemental information relating to oil and natural gas producing activities (unaudited) The following supplemental information relating to our oil and natural gas producing activities for the years ended December 31, 2015 , 2014 and 2013 is presented in accordance with ASC 932, Extractive Activities, Oil and Gas. Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities: (in thousands, except per unit amounts) Amount 2015: Proved property acquisition costs $ 7,608 Unproved property acquisition costs — Total property acquisition costs 7,608 Development 215,239 Exploration costs (1) 13,306 Lease acquisitions and other 13,017 Capitalized asset retirement costs 881 Depletion per Boe $ 10.32 Depletion per Mcfe $ 1.72 2014: Proved property acquisition costs $ 10,562 Unproved property acquisition costs — Total property acquisition costs 10,562 Development 354,199 Exploration costs (2) 5,906 Lease acquisitions and other 9,681 Capitalized asset retirement costs 576 Depletion per Boe $ 11.42 Depletion per Mcfe $ 1.90 2013: Proved property acquisition costs $ 754,370 Unproved property acquisition costs 232,020 Total property acquisition costs (3) 986,390 Development 231,447 Exploration costs (4) 38,579 Lease acquisitions and other 14,835 Capitalized asset retirement costs 514 Depletion per Boe $ 8.82 Depletion per Mcfe $ 1.47 (1) Exploration costs in 2015 primarily relate to the wells drilled in the Buda formation in South Texas. (2) Exploration costs in 2014 include $5.9 million in the Bossier shale in North Louisiana. (3) Acquisition costs in 2013 include the acquisition of properties in the Haynesville and Eagle Ford shales and our proportionate share of Compass's acquisition of shallow Cotton Valley assets. (4) Exploration costs in 2013 include $29.2 million in the Eagle Ford shale and $9.4 million in the Marcellus shale. We retain independent engineering firms to prepare or audit annual year-end estimates of our future net recoverable oil and natural gas reserves. The estimated proved net recoverable reserves we show below include only those quantities that we expect to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves that we may recover through existing wells. Proved Undeveloped Reserves include those reserves that we may recover from new wells on undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations. All of our reserves are located onshore in the continental United States of America. Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of our oil and natural gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise. Oil Natural Mmcfe (13) December 31, 2012 5,570 975,966 1,009,386 Purchase of reserves in place (1) 16,022 304,139 400,271 Discoveries and extensions (2) 5,960 49,912 85,672 Revisions of previous estimates: Changes in price 457 276,730 279,472 Other factors (3) (3,219 ) (111,141 ) (130,455 ) Sales of reserves in place (4) (8,224 ) (308,850 ) (358,194 ) Production (1,188 ) (154,779 ) (161,907 ) December 31, 2013 15,378 1,031,977 1,124,245 Purchase of reserves in place (5) — 7,316 7,316 Discoveries and extensions (6) 4,164 70,544 95,528 Revisions of previous estimates: Changes in price 45 168,064 168,334 Other factors (7) 1,737 120,802 131,224 Sales of reserves in place (8) (1,401 ) (118,705 ) (127,111 ) Production (2,236 ) (122,324 ) (135,740 ) December 31, 2014 17,687 1,157,674 1,263,796 Purchase of reserves in place (9) 459 122 2,876 Discoveries and extensions (10) 7,602 152,473 198,085 Revisions of previous estimates: Changes in price (2,821 ) (598,865 ) (615,791 ) Other factors (11) (145 ) 184,641 183,771 Sales of reserves in place (1 ) (1,445 ) (1,451 ) Production (2,342 ) (109,926 ) (123,978 ) December 31, 2015 20,439 784,674 907,308 Estimated Quantities of Proved Developed and Proved Undeveloped Reserves Oil Natural Mmcfe Proved developed: December 31, 2015 12,056 364,932 437,268 December 31, 2014 14,429 504,636 591,210 December 31, 2013 11,274 669,644 737,291 Proved undeveloped: December 31, 2015 8,383 419,742 470,040 December 31, 2014 3,258 653,038 672,586 December 31, 2013 4,104 362,333 386,954 (1) Purchases of reserves in place include 115.7 Bcfe in the Eagle Ford shale, 260.0 Bcfe in the Haynesville shale, and 24.6 Bcfe for our proportionate share of Compass's acquisition of shallow Cotton Valley assets in East Texas/North Louisiana. (2) New discoveries and extensions in 2013 include 36.5 Bcfe in the Eagle Ford shale, 33.6 Bcfe in the Marcellus shale, 10.2 Bcfe in the Haynesville shale, 3.9 Bcfe for conventional properties held by Compass in the Permian Basin, and 1.5 Bcfe for shale properties in the Permian Basin. (3) Total revisions due to Other factors were downward revisions primarily in the Haynesville shale as a result of operational matters including scaling, liquid loading due to high-line pressure and the impact of drainage on new wells drilled directly offset to the unit wells. (4) Sales of reserves in place in 2013 include 327.6 Bcfe as a result of our contribution of properties to Compass and 30.6 Bcfe from the sale of undeveloped properties in the Eagle Ford in connection with the Participation Agreement. (5) Purchases of reserves in place in 2014 consist primarily of our acquisition of certain proved developed producing properties in the Shelby area of East Texas. (6) New discoveries and extensions in 2014 included 48.7 Bcfe in the Haynesville shale, 26.1 Bcfe in the Eagle Ford Shale and 19.7 Bcfe in the Bossier shale. The discoveries and extensions within the Haynesville and Bossier shales primarily related to our development of properties within the Shelby area of East Texas. (7) Total revisions due to Other factors include upward revisions of approximately 67.1 Bcfe in the Shelby area, approximately 45.9 Bcfe in the Appalachia region, and approximately 5.8 Bcfe in the Holly area. The upward revisions were primarily due to improved well performance resulting from enhanced well designs and completion techniques. (8) Sales of reserves in place in 2014 consist primarily of the sale of our entire interest in Compass. (9) Purchases of reserves in place include the acquisition of certain proved developed producing properties in the Eagle Ford shale in connection with the Participation Agreement. (10) New discoveries and extensions in 2015 include 84.9 Bcfe and 41.0 Bcfe in the Haynesville shale and Bossier shale, respectively, related to our development of properties within the Shelby area of East Texas. Additionally, extensions and discoveries in 2015 included 24.7 Bcfe in the in the Haynesville shale related to the development of the Holly area in North Louisiana and 47.5 Bcfe in the Eagle Ford shale. (11) Total revisions due to Other factors include upward revisions of approximately 152.2 Bcfe in the North Louisiana Holly area and are primarily due to modifications in the well design to incorporate more proppant and longer laterals. The upward revisions also included 36.7 Bcfe from our East Texas region primarily due to strong results in both the Haynesville and Bossier shales based on our enhanced completion methods. The upward revisions also reflect a reduction in capital costs and operating expenses. (12) Beginning in 2015, we began reporting our NGLs as a component of natural gas as NGLs are not considered to be significant. Primarily all of our prior period NGLs were associated with properties owned by Compass, which EXCO divested in 2014. Prior period information has been conformed to be consistent with current period information. (13) The above reserves do not include our equity interest in OPCO, which was not significant in any period presented. Standardized measure of discounted future net cash flows We have summarized the Standardized Measure related to our proved oil and natural gas reserves. We have based the following summary on a valuation of Proved Reserves using discounted cash flows based on prices as prescribed by the SEC, costs and economic conditions and a 10% discount rate. The additions to Proved Reserves from the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, the information presented below should not be viewed as an estimate of the fair value of our oil and natural gas properties, nor should it be indicative of any trends. (in thousands) Amount Year ended December 31, 2015: Future cash inflows $ 2,684,362 Future production costs 1,280,795 Future development costs 641,768 Future income taxes — Future net cash flows 761,799 Discount of future net cash flows at 10% per annum 359,666 Standardized measure of discounted future net cash flows $ 402,133 Year ended December 31, 2014: Future cash inflows $ 6,097,207 Future production costs 2,094,796 Future development costs 1,124,873 Future income taxes — Future net cash flows 2,877,538 Discount of future net cash flows at 10% per annum 1,334,951 Standardized measure of discounted future net cash flows $ 1,542,587 Year ended December 31, 2013: Future cash inflows $ 5,176,030 Future production costs 2,207,230 Future development costs 904,116 Future income taxes — Future net cash flows 2,064,684 Discount of future net cash flows at 10% per annum 812,411 Standardized measure of discounted future net cash flows $ 1,252,273 During recent years, prices paid for oil and natural gas have fluctuated significantly. The reference prices at December 31, 2015 , 2014 and 2013 used in the above table, were $50.28 , $94.99 and $96.78 per Bbl of oil, respectively, and $2.59 , $4.35 and $3.67 per Mmbtu of natural gas, respectively. Each of the reference prices for oil and natural gas were adjusted for quality factors and regional differentials. These prices reflect the SEC rules requiring the use of simple average of the first day of the month price for the previous 12 month period for natural gas at Henry Hub and West Texas Intermediate crude oil at Cushing, Oklahoma. The following are the principal sources of change in the Standardized Measure: (in thousands) Amount Year ended December 31, 2015: Sales and transfers of oil and natural gas produced $ (152,937 ) Net changes in prices and production costs (1,438,490 ) Extensions and discoveries, net of future development and production costs 99,818 Development costs during the period 109,895 Changes in estimated future development costs 407,780 Revisions of previous quantity estimates (232,325 ) Sales of reserves in place (1,632 ) Purchase of reserves in place 6,892 Accretion of discount before income taxes 126,533 Changes in timing and other (65,988 ) Net change in income taxes — Net change $ (1,140,454 ) Year ended December 31, 2014: Sales and transfers of oil and natural gas produced $ (464,369 ) Net changes in prices and production costs 279,944 Extensions and discoveries, net of future development and production costs 196,796 Development costs during the period 189,155 Changes in estimated future development costs (254,737 ) Revisions of previous quantity estimates 412,296 Sales of reserves in place (148,226 ) Purchase of reserves in place 13,507 Accretion of discount before income taxes 125,227 Changes in timing and other (59,279 ) Net change in income taxes — Net change $ 290,314 Year ended December 31, 2013: Sales and transfers of oil and natural gas produced $ (450,415 ) Net changes in prices and production costs 582,725 Extensions and discoveries, net of future development and production costs 197,223 Development costs during the period 55,196 Changes in estimated future development costs (251,484 ) Revisions of previous quantity estimates 98,283 Sales of reserves in place (315,758 ) Purchase of reserves in place 604,366 Accretion of discount before income taxes 69,615 Changes in timing and other (33,625 ) Net change in income taxes — Net change $ 556,126 Costs not subject to amortization The following table summarizes the categories of costs comprising the amount of unproved properties not subject to amortization by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The majority of the evaluation activities are expected to be completed within one to seven years. (in thousands) Total 2015 2014 2013 2012 and Property acquisition costs $ 75,019 $ 11,121 $ 7,862 $ 12,403 $ 43,633 Exploration and development 12,100 12,100 — — — Capitalized interest 28,258 8,464 8,604 5,384 5,806 Total $ 115,377 $ 31,685 $ 16,466 $ 17,787 $ 49,439

Summary Of Significant Accoun24

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Principles of consolidation	Principles of consolidation We consolidate all of our subsidiaries in the accompanying Consolidated Balance Sheets as of December 31, 2015 and 2014 and the Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Changes in Shareholders' Equity for the years ended December 31, 2015 , 2014 and 2013 . Investments in unconsolidated affiliates in which we are able to exercise significant influence are accounted for using the equity method. We use the cost method of accounting for investments in unconsolidated affiliates in which we are not able to exercise significant influence. All intercompany transactions and accounts have been eliminated. We report our interests in oil and natural gas properties using the proportional consolidation method of accounting. We reported our 25.5% interest in Compass Production Partners, L.P. ("Compass") using proportional consolidation for the period from its formation on February 14, 2013 to the sale of our interests on October 31, 2014. See further discussion in "Note 3. Acquisitions, divestitures and other significant events."
Management estimates	Management estimates In preparing the consolidated financial statements in conformity with GAAP, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses during the reporting periods. The more significant estimates pertain to proved oil and natural gas reserve volumes, future development costs, asset retirement obligations, equity-based compensation, estimates relating to oil and natural gas revenues and expenses, accrued liabilities, the fair market value of assets and liabilities acquired in business combinations, derivatives and goodwill. Actual results may differ from management's estimates.
Cash equivalents	Cash equivalents We consider all highly liquid investments with maturities of three months or less when purchased, to be cash equivalents.
Restricted cash	Restricted cash The restricted cash on our balance sheet is principally comprised of our share of an evergreen escrow account with BG Group that is used to fund our share of development operations in East Texas and North Louisiana. Funds held in this escrow account are restricted and can be used primarily for drilling and operations in East Texas and North Louisiana. The restricted cash also includes accrued fees payable to Energy Strategic Advisory Services LLC ("ESAS") upon completion of its entire first year of service and required investment with EXCO.
Concentration of credit risk and accounts receivable	Concentration of credit risk and accounts receivable Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, trade receivables and our derivative financial instruments. We place our cash with financial institutions which we believe have sufficient credit quality to minimize risk of loss. We sell oil and natural gas to various customers. In addition, we participate with other parties in the drilling, completion and operation of oil and natural gas wells. The majority of our accounts receivable are due from either purchasers of oil or natural gas or participants in oil and natural gas wells for which we serve as the operator. We have the right to offset future revenues against unpaid charges related to wells which we operate. Oil and natural gas receivables are generally uncollateralized. The allowance for doubtful accounts was immaterial at both December 31, 2015 and 2014 . We place our derivative financial instruments with financial institutions that we believe have high credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with our counterparties on our derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty.
Derivative financial instruments	Derivative financial instruments We use derivative financial instruments to mitigate the impacts of commodity price fluctuations, protect our returns on investments and achieve a more predictable cash flow. Financial Accounting Standards Board ("FASB"), Accounting Standards Codification, ("ASC"), Topic 815, Derivatives and Hedging, ("ASC 815"), requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its estimated fair value. ASC 815 requires that changes in the derivative's estimated fair value be recognized in earnings unless specific hedge accounting criteria are met, or exemptions for normal purchases and normal sales as permitted by ASC 815 exist. We do not designate our derivative financial instruments as hedging instruments and, as a result, recognize the change in a derivative's estimated fair value in earnings as a component of other income or expense. Our derivative financial instruments are not held for trading purposes.
Oil and natural gas properties	Oil and natural gas properties The accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives: the full cost method or the successful efforts method. 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. Our unproved property costs, which include unproved oil and natural gas properties, properties under development, and major development projects, collectively totaled $115.4 million and $276.0 million as of December 31, 2015 and 2014 , respectively, and are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extension or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. In determining whether such costs should be impaired or transferred, we evaluate lease expiration dates, recent drilling results, future development plans and current market values. Our undeveloped properties are predominantly held-by-production, which reduces the risk of impairment as a result of lease expirations. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. As a result of our evaluation, we impaired approximately $88.1 million of unproved properties which were transferred to the depletable portion of the full cost pool during the year ended December 31, 2015 . The impairment was recorded to reflect the estimated fair value of our undeveloped properties as a result of the decline in oil and natural gas prices. The impairment also included certain acreage expiring within the next year and related properties that were no longer part of our drilling plans. See "Note 6. Fair value measurements" for further discussion. We did no t record an impairment of undeveloped properties during 2014 and recorded an impairment of $1.0 million during 2013. We capitalize interest on the costs related to the acquisition of undeveloped acreage in accordance with FASB ASC 835-20 , Capitalization of Interest . When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we cease capitalizing interest related to these properties. We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs less estimated salvage value are divided by the total estimated quantities of Proved Reserves. This rate is applied to our total production for the quarter, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our acquisition, exploration, exploitation and development activities. Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the amortization rate and/or the relationship between capitalized costs and Proved Reserves. Pursuant to Rule 4-10(c)(4) of Regulation S-X, at the end of each quarterly period, companies that use the full cost method of accounting for their 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 a ceiling test 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 Release No. 33-8995, 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. The ceiling test for each period presented 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 12 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) December 31, 2015 $ 50.28 $ 2.59 December 31, 2014 94.99 4.35 December 31, 2013 96.78 3.67 For the year ended December 31, 2015 , we recognized impairments to our proved oil and natural gas properties of $1.2 billion . The impairments were primarily due to the decline in oil and natural gas prices partially offset by upward revisions in the oil and natural gas reserves primarily as a result of recent modifications to our well design in the North Louisiana and East Texas regions. For the year ended December 31, 2014, we did no t recognize an impairment to our proved oil and natural gas properties. For the year ended December 31, 2013, we recognized impairments of $108.5 million to our proved oil and natural gas properties. The impairments for the year ended December 31, 2013 were primarily due to low natural gas prices for the trailing 12 months at the end of the first quarter of 2013, downward revisions to the reserves of our Haynesville shale properties based on operational matters, narrowing of basis differentials between oil price indices, and higher costs associated with the gathering and transportation of our natural gas production from the Eagle Ford shale. We may incur additional impairments to our oil and natural gas properties in 2016 if oil and natural gas prices do not increase. Under full cost accounting rules, any ceiling test impairments of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedging instruments, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computations. The evaluation of impairment of our oil and natural gas properties includes estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of 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.
Inventory	Inventory Inventory includes tubular goods and other lease and well equipment which we plan to utilize in our ongoing exploration and development activities and is carried at the lower of cost or market value. The cost of inventory is capitalized in our full cost pool or gathering system assets once it has been placed into service.
Other property and equipment	Other property and equipment Other property and equipment is primarily comprised of office, field and other equipment which are capitalized at cost and depreciated on a straight line basis over their estimated useful lives ranging from 3 to 15 years and the surface acreage we own in our South Texas region.
Goodwill	Goodwill In accordance with FASB ASC 350-20, Intangibles-Goodwill and Other , goodwill is not amortized, but is tested for impairment on an annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed as of December 31 of each year. We performed impairment tests as of June 30, 2015 and September 30, 2015 as a result of continued depressed commodity prices and recent impairments of our oil and natural gas properties. Losses, if any, resulting from impairment tests will be reflected in operating income or loss in the Consolidated Statements of Operations. We apply a two-part, equally weighted approach in determining the fair value of our business as part of the goodwill impairment test. We perform an income approach, which uses a discounted cash flow model to value our business, and a market approach, in which our value is determined using trading metrics and transaction multiples of peer companies. We consider our enterprise value to be the combined market capitalization plus the fair value of our debt in determining the fair value of our reporting unit and corroborate the results with the valuation model.
Asset retirement obligations	Asset retirement obligations We apply FASB ASC 410-20, Asset Retirement and Environmental Obligations ("ASC 410-20") to account for estimated future plugging and abandonment costs. ASC 410-20 requires legal obligations associated with the retirement of long-lived assets to be recognized at their estimated fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Our asset retirement obligations primarily represent the present value of the estimated amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state laws. The following is a reconciliation of our asset retirement obligations for the periods indicated: December 31, (in thousands) 2015 2014 2013 Asset retirement obligations at beginning of period $ 36,755 $ 42,954 $ 61,864 Activity during the period: Liabilities incurred during the period 881 576 514 Revisions in estimated assumptions 3,215 — 1,268 Liabilities settled during the period (293 ) (33 ) (187 ) Adjustment to liability due to acquisitions 180 107 5,566 Adjustment to liability due to divestitures (1) (1,367 ) (9,539 ) (28,585 ) Accretion of discount 2,277 2,690 2,514 Asset retirement obligations at end of period 41,648 36,755 42,954 Less current portion 845 1,769 191 Long-term portion $ 40,803 $ 34,986 $ 42,763 (1) For the year ended December 31, 2014, the adjustment to liability due to divestitures consisted primarily of $9.4 million from the sale of our interest in Compass. For the year ended December 31, 2013, the adjustment to liability due to divestitures consisted primarily of $28.3 million from the contribution of our certain conventional assets to Compass. 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.
Revenue recognition and gas imbalances	Revenue recognition and gas imbalances We use the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers.
Gathering and transportation	Gathering and transportation We generally sell oil and natural gas under two types of agreements which are common in our industry. Both types of agreements include a transportation charge. One is a net-back arrangement, under which we sell oil or natural gas at the wellhead and collect a price, net of the transportation incurred by the purchaser. In this case, we record sales at the price received from the purchaser, net of the transportation costs. Under the other arrangement, we sell oil or natural gas at a specific delivery point, pay transportation to a third party and receive proceeds from the purchaser with no transportation deduction. In this case, we record the transportation cost as gathering and transportation expense. As such, our computed realized prices, before the impact of derivative financial instruments, include revenues which are reported under two separate bases.
Capitalization of internal costs	Capitalization of internal costs As part of our proved developed oil and natural gas properties, we capitalize a portion of salaries and related share-based compensation for employees who are directly involved in the acquisition, exploration, exploitation and development of oil and natural gas properties.
Overhead reimbursement fees	Overhead reimbursement fees We have classified fees from overhead charges billed to working interest owners of $13.1 million , $13.5 million and $10.5 million for the years ended December 31, 2015 , 2014 and 2013 , respectively, as a reduction of general and administrative expenses in the accompanying Consolidated Statements of Operations. We classified our share of these charges as oil and natural gas production costs in the amount of $5.7 million , $6.4 million and $5.8 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. In addition, we have agreements with BG Group that allow us to bill each other certain personnel costs and related fees incurred on behalf of the joint ventures in the East Texas, North Louisiana and Appalachia regions. In connection with the formation of Compass, we entered into an agreement to perform certain operational, managerial, and administrative services. Compass reimbursed us for costs incurred in connection with the performance of these services based on an agreed upon service fee. As a result of the Compass sale, this agreement was terminated on October 31, 2014 and we entered into a customary transition services agreement pursuant to which EXCO provided certain transition services to Compass until April 2015. For the years ended December 31, 2015 , 2014 and 2013 , general and administrative expenses were reduced by $15.9 million , $24.7 million and $26.8 million , respectively, for recoveries of fees for our personnel and services provided to our joint ventures and other partners. These recoveries are net of fees charged to us by BG Group for their personnel and services.
Environmental costs	Environmental costs Environmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by past operations are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently available facts related to each site.
Income taxes	Income taxes Income taxes are accounted for in accordance with FASB ASC 740, Income Taxes ("ASC 740"), under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in earnings in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes ("ASU 2015-17"). Prior to ASU 2015-17, GAAP required an entity to separate deferred income tax asset and liabilities into current and noncurrent amounts on the balance sheet. ASU 2015-17 requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. ASU 2015-17 is effective for annual and interim periods beginning after December 15, 2016 and early adoption is permitted. ASU 2015-17 may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We adopted ASU 2015-17 in 2015 and applied the guidance retrospectively which resulted in the reclassification of $35.9 million of net current deferred income tax liabilities to noncurrent as of December 31, 2014. The requirement that deferred tax liabilities and assets be offset and presented as a single amount was not affected by this amendment. See "Note 12. Income taxes" for further discussion and application of ASU 2015-17 to prior period information.
Earnings per share	Earnings per share We account for earnings per share in accordance with FASB ASC 260-10, Earnings Per Share ("ASC 260-10"). ASC 260-10 requires companies to present two calculations of earnings per share ("EPS"); basic and diluted. Basic EPS is based on the weighted average number of common shares outstanding during the period, excluding stock options, restricted share units, restricted share awards and warrants. Diluted EPS is computed in the same manner as basic EPS after assuming the issuance of common shares for all potentially dilutive common share equivalents, which include stock options, restricted share units, restricted share awards and warrants, whether exercisable or not. Our diluted EPS for the year ended December 31, 2013 also included subscription rights which were the result of the rights offering of our common shares as discussed in "Note 15. Rights Offering and other equity transactions".
Equity-based compensation	Equity-based compensation Our equity-based compensation includes share-based compensation to employees which we account for in accordance with FASB ASC Topic 718, Compensation-Stock Compensation ("ASC 718") and equity-based compensation for warrants issued to ESAS which we account for in accordance with FASB ASC Topic 505-50, Equity-Based Payments to Non-Employees ("ASC 505-50"). ASC 718 requires all share-based payments to employees, including grants of employee stock options, restricted share units and restricted share awards, to be recognized in our Consolidated Statements of Operations based on their estimated fair values. We recognize expense on a straight-line basis over the vesting period of the option, restricted share unit or restricted share award. We capitalize part of our share-based compensation that is attributable to our acquisition, exploration, exploitation and development activities. Our 2005 Amended and Restated Long-Term Incentive Plan ("2005 Incentive Plan") provides for the granting of options and other equity incentive awards of our common shares in accordance with terms within the agreements. New shares will be issued for any options exercised or awards granted. Under the 2005 Incentive Plan, we have only issued stock options, restricted share units and restricted share awards, although the plan allows for other share-based awards.
Recent accounting pronouncements	Recent accounting pronouncements In April 2015, the FASB issued Accounting Standards Update ("ASU") No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Prior to the adoption of ASU 2015-03, we recognized debt issuance costs as assets on our balance sheet. The recognition and measurement guidance for debt issuance costs are not affected by ASU 2015-03. ASU 2015-03 is effective for annual and interim periods beginning after December 15, 2015 and early adoption is permitted. In August 2015, the FASB issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements ("ASU 2015-15"). ASU 2015-15 clarifies that the SEC would not object to an entity deferring and presenting debt issuance costs related to a line-of-credit arrangement as an asset on the balance sheet. We adopted ASU 2015-03 and ASU 2015-15 in the fourth quarter of 2015 and applied the new guidance retrospectively to all periods presented. The adoption of ASU 2015-03 and ASU 2015-15 resulted in certain reclassifications of debt issuance costs on our balance sheets. See "Note 5. Debt" for additional information. In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments ("ASU 2015-16"). ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in this update require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in this update require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. ASU 2015-16 is effective for annual and interim periods beginning after December 15, 2015 and early adoption is permitted. We will apply this guidance to business combinations, when applicable, occurring after the effective date of ASU 2015-16. In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes ("ASU 2015-17"). Prior to ASU 2015-17, GAAP required an entity to separate deferred income tax asset and liabilities into current and noncurrent amounts on the balance sheet. ASU 2015-17 requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. ASU 2015-17 is effective for annual and interim periods beginning after December 15, 2016 and early adoption is permitted. ASU 2015-17 may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We adopted ASU 2015-17 in 2015 and applied the guidance retrospectively which resulted in the reclassification of $35.9 million of net current deferred income tax liabilities to noncurrent as of December 31, 2014. The requirement that deferred tax liabilities and assets be offset and presented as a single amount was not affected by this amendment. See "Note 12. Income taxes" for further discussion and application of ASU 2015-17 to prior period information. In February 2016, the FASB issued 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. 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. Transaction will require application of the new guidance at the beginning of the earliest comparative period presented. We are currently assessing the potential impact of ASU 2016-02 and expect it will have a material impact on our consolidated financial condition and results of operations upon adoption.
Debt issuance cost [Policy Text Block]	In April 2015, the FASB issued Accounting Standards Update ("ASU") No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Prior to the adoption of ASU 2015-03, we recognized debt issuance costs as assets on our balance sheet. The recognition and measurement guidance for debt issuance costs are not affected by ASU 2015-03. ASU 2015-03 is effective for annual and interim periods beginning after December 15, 2015 and early adoption is permitted. In August 2015, the FASB issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements ("ASU 2015-15"). ASU 2015-15 clarifies that the SEC would not object to an entity deferring and presenting debt issuance costs related to a line-of-credit arrangement as an asset on the balance sheet. We adopted ASU 2015-03 and ASU 2015-15 in the fourth quarter of 2015 and applied the new guidance retrospectively to all periods presented. The adoption of ASU 2015-03 and ASU 2015-15 resulted in certain reclassifications of debt issuance costs on our balance sheets.

Summary Of Significant Accoun25

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Average spot price [Table Text Block]	The ceiling test for each period presented 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 12 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) December 31, 2015 $ 50.28 $ 2.59 December 31, 2014 94.99 4.35 December 31, 2013 96.78 3.67
Reconciliation Of Asset Retirement Obligations	The following is a reconciliation of our asset retirement obligations for the periods indicated: December 31, (in thousands) 2015 2014 2013 Asset retirement obligations at beginning of period $ 36,755 $ 42,954 $ 61,864 Activity during the period: Liabilities incurred during the period 881 576 514 Revisions in estimated assumptions 3,215 — 1,268 Liabilities settled during the period (293 ) (33 ) (187 ) Adjustment to liability due to acquisitions 180 107 5,566 Adjustment to liability due to divestitures (1) (1,367 ) (9,539 ) (28,585 ) Accretion of discount 2,277 2,690 2,514 Asset retirement obligations at end of period 41,648 36,755 42,954 Less current portion 845 1,769 191 Long-term portion $ 40,803 $ 34,986 $ 42,763 (1) For the year ended December 31, 2014, the adjustment to liability due to divestitures consisted primarily of $9.4 million from the sale of our interest in Compass. For the year ended December 31, 2013, the adjustment to liability due to divestitures consisted primarily of $28.3 million from the contribution of our certain conventional assets to Compass. 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.

Acquisitions, Divestitures An26

Acquisitions, Divestitures And Other Significant Events (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition	The following table presents a summary of the fair value of assets acquired and liabilities assumed as part of the Haynesville and Eagle Ford acquisitions based on the final settlement statements as of July 12, 2013 and July 31, 2013, respectively: Purchase Price Allocation (in thousands): Haynesville Acquired Properties Eagle Ford Acquired Properties Assets acquired: Unproved oil and natural gas properties $ 2,319 $ 227,869 Proved developed and undeveloped oil and natural gas properties 282,918 437,616 Liabilities assumed: Accounts payable and accrued liabilities — (580 ) Revenues and royalties payable (3,526 ) — Asset retirement obligations (610 ) (3,060 ) Total purchase price $ 281,101 $ 661,845

Derivative Financial Instrume27

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Fair Value Of Derivative Financial Instruments	Fair Value of Derivative Financial Instruments (in thousands) December 31, 2015 December 31, 2014 Derivative financial instruments - Current assets $ 39,499 $ 97,278 Derivative financial instruments - Long-term assets 6,109 2,138 Derivative financial instruments - Current liabilities (16 ) (892 ) Derivative financial instruments - Long-term liabilities — — Net derivative financial instruments $ 45,592 $ 98,524
Effect Of Derivative Financial Instruments	The Effect of Derivative Financial Instruments Year Ended December 31, (in thousands) 2015 2014 2013 Gain (loss) on derivative financial instruments $ 75,869 $ 87,665 $ (320 )
Fair Value Of Oil And Natural Gas Derivative Financial Instruments	The following table presents the volumes and fair value of our oil and natural gas derivative financial instruments as of December 31, 2015 : (dollars in thousands, except prices) Volume Bbtu/Mbbl Weighted average strike price per Mmbtu/Bbl Fair value at December 31, 2015 Natural gas: Swaps: 2016 34,770 $ 3.09 $ 20,894 2017 10,950 3.28 5,279 2018 3,650 3.15 830 Total natural gas $ 27,003 Oil: Swaps: 2016 915 $ 61.89 $ 18,589 Total oil $ 18,589 Total oil and natural gas derivative financial instruments $ 45,592

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Long-term Debt, Current and Noncurrent [Abstract]
Schedule Of Debt	The carrying value of our total debt is summarized as follows: (in thousands) December 31, 2015 December 31, 2014 EXCO Resources Credit Agreement $ 67,492 $ 202,492 Exchange Term Loan 641,172 — Fairfax Term Loan 300,000 — 2018 Notes 158,015 750,000 Unamortized discount on 2018 Notes (932 ) (5,957 ) 2022 Notes 222,826 500,000 Deferred financing costs, net (18,294 ) (16,019 ) Total debt, net 1,370,279 1,430,516 Less amounts due within one year 50,000 — Total debt due after one year $ 1,320,279 $ 1,430,516 December 31, 2015 (in thousands) Carrying value Deferred reduction in carrying value Unamortized discount/deferred financing costs Principal balance EXCO Resources Credit Agreement $ 67,492 $ — $ — $ 67,492 Exchange Term Loan 641,172 (241,172 ) — 400,000 Fairfax Term Loan 300,000 — — 300,000 2018 Notes 157,083 — 932 158,015 2022 Notes 222,826 — — 222,826 Deferred financing costs, net (18,294 ) — 18,294 — Total debt $ 1,370,279 $ (241,172 ) $ 19,226 $ 1,148,333 Terms and conditions of each of these debt obligations are discussed below.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Summary Of Estimated Fair Value Of Derivative Financial Instruments	December 31, 2015 (in thousands) Level 1 Level 2 Level 3 Total Oil and natural gas derivative financial instruments $ — $ 45,592 $ — $ 45,592 December 31, 2014 (in thousands) Level 1 Level 2 Level 3 Total Oil and natural gas derivative financial instruments $ — $ 98,524 $ — $ 98,524
Schedule Of Estimated Fair Value Of Other Financial Instruments	December 31, 2015 (in thousands) Level 1 Level 2 Level 3 Total 2018 Notes $ 43,170 $ — $ — $ 43,170 2022 Notes 48,376 — — 48,376 Exchange Term Loan — 278,000 — 278,000 Fairfax Term Loan — 208,500 — 208,500 December 31, 2014 (in thousands) Level 1 Level 2 Level 3 Total 2018 Notes $ 558,750 $ — $ — $ 558,750 2022 Notes 373,500 — — 373,500

Commitments And Contingencies (

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Schedule Of Future Minimum Rental Payments Under Operation Leases	The following table presents our future minimum obligations under our commercial commitments as of December 31, 2015 . The commitments do not include those of our equity method investments. (in thousands) Gathering and firm transportation services Other fixed commitments Drilling contracts Operating leases and other Total 2016 $ 120,414 $ 13,253 $ 14,997 $ 5,456 $ 154,120 2017 120,085 5,443 7,284 4,228 137,040 2018 116,365 3,210 — 3,240 122,815 2019 76,285 2,403 — 3,053 81,741 2020 48,148 1,932 — 1,560 51,640 Thereafter 135,943 1,599 — 72 137,614 Total $ 617,240 $ 27,840 $ 22,281 $ 17,609 $ 684,970
Oil and Gas Delivery Commitments and Contracts Disclosure	At December 31, 2015 , our firm transportation and gathering agreements covered the following gross volumes of natural gas: (in Bcf) Firm transportation services Gathering services 2016 270 110 2017 269 110 2018 269 100 2019 269 — 2020 177 — Thereafter 596 — Total 1,850 320

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Basic And Diluted Earnings Per Share Computations	The following table presents the basic and diluted earnings (loss) per share computations for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, (in thousands, except per share data) 2015 2014 2013 Basic net income (loss) per common share: Net income (loss) $ (1,192,381 ) $ 120,669 $ 22,204 Weighted average common shares outstanding 273,621 268,258 215,011 Net income (loss) per basic common share $ (4.36 ) $ 0.45 $ 0.10 Diluted net income (loss) per common share: Net income (loss) $ (1,192,381 ) $ 120,669 $ 22,204 Weighted average common shares outstanding 273,621 268,258 215,011 Dilutive effect of: Stock options — — — Restricted shares and restricted share units — 118 420 Warrants — — — Subscription rights — — 15,481 Weighted average common shares and common share equivalents outstanding 273,621 268,376 230,912 Net income (loss) per diluted common share $ (4.36 ) $ 0.45 $ 0.10

Equity-based compensation (Tabl

Equity-based compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Share-based Compensation [Abstract]
Stock Option Activity	The following table summarizes stock option activity related to our employees under the 2005 Incentive Plan for the years ended December 31, 2015 , 2014 and 2013 : Stock Options Weighted average exercise price per share Weighted average remaining terms (in years) Aggregate intrinsic value Options outstanding at December 31, 2012 14,015,795 $ 13.20 Granted 2,886,500 7.48 Forfeitures (4,969,877 ) 11.32 Exercised (220,675 ) 7.66 Options outstanding at December 31, 2013 11,711,743 12.69 Granted 141,525 5.24 Forfeitures (1,700,250 ) 12.71 Exercised (2,500 ) 5.22 Options outstanding at December 31, 2014 10,150,518 12.58 Granted — — Forfeitures (4,538,858 ) 12.30 Exercised — — Options outstanding at December 31, 2015 5,611,660 $ 12.81 3.4 $ — Options exercisable at December 31, 2015 5,276,336 $ 13.18 3.2 $ —
Fair Value Option Assumptions	The following assumptions were used for the options included in the table above, for the years ended December 31: 2014 2013 Expected life 7.5 years 3.8 to 7.5 years Risk-free rate of return 2.25 - 2.61 % 0.48 - 2.49 % Volatility 59.46 - 59.61 % 49.47 - 59.86 % Dividend yield 3.36 - 4.34 % 2.27 - 3.87 %
Restricted Stock Activity	A summary of our service-based restricted share activity for the years ended December 31, 2015 , 2014 and 2013 are as follows: Shares Weighted average grant date fair value per share Non-vested shares outstanding at December 31, 2012 2,806,365 $ 10.16 Granted 556,700 7.15 Vested (832,706 ) 10.47 Forfeited (602,045 ) 9.84 Non-vested shares outstanding at December 31, 2013 1,928,314 $ 9.26 Granted 1,339,782 5.20 Vested (1,109,866 ) 9.79 Forfeited (280,301 ) 6.89 Non-vested shares outstanding at December 31, 2014 1,877,929 $ 6.40 Granted 4,414,470 1.05 Vested (847,446 ) 6.80 Forfeited (903,383 ) 3.17 Non-vested shares outstanding at December 31, 2015 4,541,570 $ 1.77 Market-based restricted share awards On August 13, 2013, EXCO’s officers were granted a market-based restricted share award with vesting dependent on the Company's common share price achieving certain price targets. There were 290,200 shares outstanding on December 31, 2015, including 145,100 shares that will be vested following any 30 consecutive trading days in which the company’s common stock equals or exceeds $10.00 per share and 145,100 shares will be vested following any 30 consecutive trading days in which the Company’s common shares equals or exceeds $15.00 per share ("Target Price Awards"). The shares expire on August 13, 2018 and are subject to vesting provisions depending on when the target price attainment date occurs. No such awards were granted in 2015 or 2014 and no awards have vested to date. On July 1, 2014, EXCO's officers were granted restricted share units ("RSU") which have a vesting percentage between 0% and 200% depending on EXCO's total shareholder return in comparison to an identified peer group. These units will vest on the third anniversary of the date of grant, subject to the achievement of certain criteria. Total compensation expense will be recognized over the vesting period using the straight-line method. No such awards were granted in 2015. The grant date fair values of our market-based restricted share awards and restricted share units were determined using a Monte Carlo model which uses company-specific inputs to generate different stock price paths. A summary of our market-based restricted share activity for the years ended December 31, 2015 and 2014 is as follows: Target Price Awards RSUs Shares Weighted average grant date fair value per share Shares Weighted average grant date fair value per share Non-vested shares/units outstanding at December 31, 2014 401,400 $ 6.36 716,150 $ 7.33 Granted — — — — Vested — — — — Forfeited (111,200 ) 6.36 (169,272 ) 7.33 Non-vested shares/units outstanding at December 31, 2015 290,200 $ 6.36 546,878 $ 7.33
Schedule of Nonvested Performance-based Units Activity [Table Text Block]	A summary of the PSUs for the years ended December 31, 2015 is as follows: Shares Weighted average fair value per share Non-vested units outstanding at December 31, 2014 — $ — Granted 2,496,250 1.45 Vested — — Forfeited (381,250 ) 1.25 Non-vested units outstanding at December 31, 2015 2,115,000 $ 2.39
Reconciliation Of Share-Based Compensation Expense	The following is a reconciliation of our compensation expense for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, (in thousands) 2015 2014 2013 Equity-based compensation expense (1) $ 7,198 $ 4,962 $ 10,748 Equity-based compensation capitalized 3,428 5,498 7,288 Total equity-based compensation $ 10,626 $ 10,460 $ 18,036 Compensation expense on liability-classified awards (2) $ 396 $ — $ — (1) Equity-based compensation expense includes share-based compensation to employees and equity-based compensation for warrants issued to ESAS in 2015. (2) Compensation expense on liability-classified awards is net of compensation capitalized of $0.2 million .
Schedule of share-based payment award, performance-based units, valuation assumptions [Table Text Block]	The fair values of the PSUs were determined using a Monte Carlo model. The ranges for the assumptions used in the Monte Carlo model for the PSUs during 2015 are as follows: Assumption Range during 2015 Risk-free rate of return 0.85 - 1.18 % Volatility 62.58 - 95.79 % Dividend yield 0.00 - 0.00 %

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Accrued Income Taxes [Abstract]
Components Of Income Tax Provision (Benefit)	The income tax provision attributable to our income (loss) before income taxes for the years ended December 31, 2015 , 2014 and 2013 , consisted of the following: Year ended December 31, (in thousands) 2015 2014 2013 Current: Federal $ — $ — $ — State — — — Total current income tax (benefit) $ — $ — $ — Deferred: Federal $ (414,834 ) $ 45,797 $ 25,626 State (45,009 ) 18,960 3,239 Valuation allowance 459,843 (64,757 ) (28,865 ) Total deferred income tax (benefit) — — — Total income tax (benefit) $ — $ — $ —
Significant Components Of Deferred Tax Liabilities And Assets	Significant components of our deferred tax liabilities and assets are as follows: (in thousands) December 31, 2015 December 31, 2014 Non-current deferred tax assets: Net operating loss and AMT credits carryforwards $ 689,441 $ 781,899 Capital loss carryforwards 40,356 40,356 Equity-based compensation 17,372 14,856 Oil and natural gas properties, gathering assets, and equipment 356,471 — Debt restructuring 122,900 — Goodwill 1,308 5,419 Investment in partnerships 76,099 72,988 Other 3,387 2,668 Total non-current deferred tax assets 1,307,334 918,186 Valuation allowance (1,286,695 ) (826,852 ) Total non-current deferred tax assets 20,639 91,334 Non-current deferred tax liabilities: Oil and natural gas properties, gathering assets, and equipment $ — $ (51,961 ) Derivative financial instruments (20,639 ) (39,373 ) Total non-current deferred tax liabilities (20,639 ) (91,334 ) Net non-current deferred tax assets (liabilities) $ — $ —
Reconciliation Of Income Tax Provision (Benefit)	A reconciliation of our income tax provision (benefit) computed by applying the statutory United States federal income tax rate to our income (loss) before income taxes for the years ended December 31, 2015 , 2014 and 2013 is presented in the following table: Year Ended December 31, (in thousands) 2015 2014 2013 Federal income taxes (benefit) provision at statutory rate of 35% $ (417,333 ) $ 42,234 $ 7,772 Increases (reductions) resulting from: Goodwill — — 16,382 Adjustments to the valuation allowance 459,843 (64,757 ) (28,865 ) Non-deductible compensation 2,399 3,409 1,328 State taxes net of federal benefit (45,009 ) 3,464 3,239 State tax rate change — 15,496 — Other 100 154 144 Total income tax provision $ — $ — $ —

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Schedule Of Related Party Transactions	Year Ended December 31, (in thousands) 2015 2014 2013 Advances to OPCO $ — $ — $ 28,378 Amounts received from OPCO 30,577 53,002 43,632 As of December 31, 2015 and 2014 , the amounts owed under the service agreements were as follows: (in thousands) December 31, 2015 December 31, 2014 Amounts due to EXCO (1) $ 1,733 $ 2,799 Amounts due from EXCO (1) 10,410 — (1) Advances to OPCO are recorded in "Inventory and other" on our Condensed Consolidated Balance Sheets. Any amounts we owe to OPCO are netted against the advance until the advances are utilized. If the advances are fully utilized, we record amounts owed in "Accounts payable and accrued liabilities" on our Condensed Consolidated Balance Sheets.

Condensed Consolidating Finan35

Condensed Consolidating Financial Statements (Tables)	12 Months Ended
	Dec. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule Of Condensed Consolidating Balance Sheet	EXCO RESOURCES, INC. CONDENSED CONSOLIDATING BALANCE SHEET December 31, 2015 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 34,296 $ (22,049 ) $ — $ — $ 12,247 Restricted cash 2,100 19,120 — — 21,220 Other current assets 51,133 65,201 — — 116,334 Total current assets 87,529 62,272 — — 149,801 Equity investments — — 40,797 — 40,797 Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties and development costs not being amortized — 115,377 — — 115,377 Proved developed and undeveloped oil and natural gas properties 330,775 2,739,655 — — 3,070,430 Accumulated depletion (330,775 ) (2,296,988 ) — — (2,627,763 ) Oil and natural gas properties, net — 558,044 — — 558,044 Other property and equipment, net 749 27,063 — — 27,812 Investments in and advances to affiliates, net 616,940 — — (616,940 ) — Deferred financing costs, net 8,408 — — — 8,408 Derivative financial instruments 6,109 — — — 6,109 Goodwill 13,293 149,862 — — 163,155 Total assets $ 733,028 $ 797,241 $ 40,797 $ (616,940 ) $ 954,126 Liabilities and shareholders' equity Current liabilities $ 74,472 $ 178,447 $ — $ — $ 252,919 Long-term debt 1,320,279 — — — 1,320,279 Other long-term liabilities 600 42,651 — — 43,251 Payable to parent — 2,276,594 — (2,276,594 ) — Total shareholders' equity (662,323 ) (1,700,451 ) 40,797 1,659,654 (662,323 ) Total liabilities and shareholders' equity $ 733,028 $ 797,241 $ 40,797 $ (616,940 ) $ 954,126 EXCO RESOURCES, INC. CONDENSED CONSOLIDATING BALANCE SHEET December 31, 2014 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 86,837 $ (40,532 ) $ — $ — $ 46,305 Restricted cash — 23,970 — — 23,970 Other current assets 110,145 150,346 — — 260,491 Total current assets 196,982 133,784 — — 330,766 Equity investments — — 55,985 — 55,985 Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties and development costs not being amortized — 276,025 — — 276,025 Proved developed and undeveloped oil and natural gas properties 335,838 3,516,235 — — 3,852,073 Accumulated depletion (330,771 ) (2,083,690 ) — — (2,414,461 ) Oil and natural gas properties, net 5,067 1,708,570 — — 1,713,637 Other property and equipment, net 1,269 23,375 — — 24,644 Investments in and advances to affiliates, net 1,746,931 — — (1,746,931 ) — Deferred financing costs, net 14,617 — — — 14,617 Derivative financial instruments 2,138 — — — 2,138 Goodwill 13,293 149,862 — — 163,155 Total assets $ 1,980,297 $ 2,015,591 $ 55,985 $ (1,746,931 ) $ 2,304,942 Liabilities and shareholders' equity Current liabilities $ 39,506 $ 289,930 $ — $ — $ 329,436 Long-term debt 1,430,516 — — — 1,430,516 Other long-term liabilities 271 34,715 — — 34,986 Payable to parent — 2,058,683 — (2,058,683 ) — Total shareholders' equity 510,004 (367,737 ) 55,985 311,752 510,004 Total liabilities and shareholders' equity $ 1,980,297 $ 2,015,591 $ 55,985 $ (1,746,931 ) $ 2,304,942
Schedule Of Condensed Consolidating Statement Of Operations	EXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS For the year ended December 31, 2015 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues: Oil and natural gas $ 4 $ 328,327 $ — $ — $ 328,331 Costs and expenses: Oil and natural gas production 37 76,496 — — 76,533 Gathering and transportation — 99,321 — — 99,321 Depletion, depreciation and amortization 943 214,483 — — 215,426 Impairment of oil and natural gas properties 9,316 1,206,054 — — 1,215,370 Accretion of discount on asset retirement obligations 4 2,273 — — 2,277 General and administrative (4,313 ) 63,131 — — 58,818 Other operating items 1,646 (1,185 ) — — 461 Total costs and expenses 7,633 1,660,573 — — 1,668,206 Operating loss (7,629 ) (1,332,246 ) — — (1,339,875 ) Other income (expense): Interest expense, net (106,082 ) — — — (106,082 ) Gain on derivative financial instruments 75,869 — — — 75,869 Gain on restructuring and extinguishment of debt 193,276 — — — 193,276 Other income 87 35 — — 122 Equity loss — — (15,691 ) — (15,691 ) Net loss from consolidated subsidiaries (1,347,902 ) — — 1,347,902 — Total other income (expense) (1,184,752 ) 35 (15,691 ) 1,347,902 147,494 Loss before income taxes (1,192,381 ) (1,332,211 ) (15,691 ) 1,347,902 (1,192,381 ) Income tax expense — — — — — Net loss $ (1,192,381 ) $ (1,332,211 ) $ (15,691 ) $ 1,347,902 $ (1,192,381 ) EXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS For the year ended December 31, 2014 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues: Oil and natural gas $ 3,649 $ 614,889 $ 41,731 $ — $ 660,269 Costs and expenses: Oil and natural gas production 394 77,334 16,598 — 94,326 Gathering and transportation — 97,784 3,790 — 101,574 Depletion, depreciation and amortization 3,174 244,761 15,634 — 263,569 Impairment of oil and natural gas properties — — — — — Accretion of discount on asset retirement obligations 16 2,107 567 — 2,690 General and administrative (3,342 ) 66,686 2,576 — 65,920 Other operating items (134 ) 5,459 (10 ) — 5,315 Total costs and expenses 108 494,131 39,155 — 533,394 Operating income 3,541 120,758 2,576 — 126,875 Other income (expense): Interest expense, net (92,049 ) — (2,235 ) — (94,284 ) Gain on derivative financial instruments 87,565 — 100 — 87,665 Other income 226 — 15 — 241 Equity income — — 172 — 172 Net earnings from consolidated subsidiaries 121,386 — — (121,386 ) — Total other income (expense) 117,128 — (1,948 ) (121,386 ) (6,206 ) Income before income taxes 120,669 120,758 628 (121,386 ) 120,669 Income tax expense — — — — — Net income $ 120,669 $ 120,758 $ 628 $ (121,386 ) $ 120,669 EXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS For the year ended December 31, 2013 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues: Oil and natural gas $ 9,136 $ 582,158 $ 43,015 $ — $ 634,309 Costs and expenses: Oil and natural gas production 2,440 63,716 17,092 — 83,248 Gathering and transportation — 97,166 3,479 — 100,645 Depletion, depreciation and amortization 5,917 225,499 14,359 — 245,775 Impairment of oil and natural gas properties — 108,546 — — 108,546 Accretion of discount on asset retirement obligations 63 1,881 570 — 2,514 General and administrative 23,125 66,558 2,195 — 91,878 Gain on divestitures and other operating items (25,950 ) (151,549 ) (19 ) — (177,518 ) Total costs and expenses 5,595 411,817 37,676 — 455,088 Operating income (loss) 3,541 170,341 5,339 — 179,221 Other income (expense): Interest expense, net (99,815 ) — (2,774 ) — (102,589 ) Gain (loss) on derivative financial instruments 1,439 (177 ) (1,582 ) — (320 ) Other income (loss) (1,068 ) 229 11 — (828 ) Equity loss — — (53,280 ) — (53,280 ) Net earnings from consolidated subsidiaries 118,107 — — (118,107 ) — Total other income (expense) 18,663 52 (57,625 ) (118,107 ) (157,017 ) Income (loss) before income taxes 22,204 170,393 (52,286 ) (118,107 ) 22,204 Income tax expense — — — — — Net income (loss) $ 22,204 $ 170,393 $ (52,286 ) $ (118,107 ) $ 22,204
Schedule Of Condensed Consolidating Statement Of Cash Flows	EXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS For the year ended December 31, 2015 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Operating Activities: Net cash provided by operating activities $ 34,532 $ 99,495 $ — $ — $ 134,027 Investing Activities: Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions (2,601 ) (322,597 ) — — (325,198 ) Proceeds from disposition of property and equipment 686 6,711 — — 7,397 Restricted cash — 4,850 — — 4,850 Net changes in advances to joint ventures — 10,663 — — 10,663 Equity investments and other — 1,455 — — 1,455 Advances/investments with affiliates (217,906 ) 217,906 — — — Net cash used in investing activities (219,821 ) (81,012 ) — — (300,833 ) Financing Activities: Borrowings under credit agreements 165,000 — — — 165,000 Repayments under credit agreements (300,000 ) — — — (300,000 ) Proceeds received from issuance of Fairfax Term Loan 300,000 — — — 300,000 Repurchases of 2018 Notes (12,008 ) — — — (12,008 ) Payment on Exchange Term Loan (8,827 ) — — — (8,827 ) Proceeds from issuance of common shares, net 9,693 — — — 9,693 Payment of common share dividends (164 ) — — — (164 ) Deferred financing costs and other (20,946 ) — — — (20,946 ) Net cash provided by financing activities 132,748 — — — 132,748 Net increase (decrease) in cash (52,541 ) 18,483 — — (34,058 ) Cash at beginning of period 86,837 (40,532 ) — — 46,305 Cash at end of period $ 34,296 $ (22,049 ) $ — $ — $ 12,247 EXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS For the year ended December 31, 2014 (in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Operating Activities: Net cash provided by (used in) operating activities $ (84,067 ) $ 428,029 $ 18,131 $ — $ 362,093 Investing Activities: Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions (2,531 ) (395,974 ) (4,061 ) — (402,566 ) Proceeds from disposition of property and equipment 99,612 95,594 (7,551 ) — 187,655 Restricted cash — (3,400 ) — — (3,400 ) Net changes in advances to joint ventures — (5,026 ) — — (5,026 ) Distributions from Compass 5,856 — — (5,856 ) — Equity investments and other — 1,749 — — 1,749 Advances/investments with affiliates 125,612 (125,612 ) — — — Net cash provided by (used in) investing activities 228,549 (432,669 ) (11,612 ) (5,856 ) (221,588 ) Financing Activities: Borrowings under credit agreements 100,000 — — — 100,000 Repayments under credit agreements (959,874 ) — (5,096 ) — (964,970 ) Proceeds received from issuance of 2022 Notes 500,000 — — — 500,000 Proceeds from issuance of common shares, net 271,773 — — — 271,773 Payment of common share dividends (41,060 ) — — — (41,060 ) Compass cash distribution — — (5,856 ) 5,856 — Deferred financing costs and other (10,324 ) — (102 ) — (10,426 ) Net cash used in financing activities (139,485 ) — (11,054 ) 5,856 (144,683 ) Net increase (decrease) in cash 4,997 (4,640 ) (4,535 ) — (4,178 ) Cash at beginning of period 81,840 (35,892 ) 4,535 — 50,483 Cash at end of period $ 86,837 $ (40,532 ) $ — $ — $ 46,305 EXCO RESOURCES, INC. CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS For the year ended December 31, 2013 (in thousands) Resources Guarantor Subsidiaries Non-guarantor subsidiaries Eliminations Consolidated Operating Activities: Net cash provided by (used in) operating activities $ (32,678 ) $ 365,770 $ 17,542 $ — $ 350,634 Investing Activities: Additions to oil and natural gas properties, gathering assets and equipment (15,767 ) (1,242,667 ) (38,818 ) — (1,297,252 ) Proceeds from disposition of property and equipment 244,500 505,128 — — 749,628 Restricted cash — 49,515 — — 49,515 Net changes in advances to joint ventures — 10,645 — — 10,645 Distributions from Compass 3,825 — — (3,825 ) — Equity investments and other (1,303 ) 236,289 — — 234,986 Advances/investments with affiliates (59,575 ) 59,575 — — — Net cash provided by (used in) investing activities 171,680 (381,515 ) (38,818 ) (3,825 ) (252,478 ) Financing Activities: Borrowings under the credit agreements 967,766 — 36,757 — 1,004,523 Repayments under the credit agreements (1,015,900 ) — (6,885 ) — (1,022,785 ) Proceeds from issuance of common shares, net 1,712 — — — 1,712 Payment of common share dividends (43,214 ) — — — (43,214 ) Compass cash distribution — — (3,825 ) 3,825 — Deferred financing costs and other (33,317 ) — (236 ) — (33,553 ) Net cash provided by (used in) financing activities (122,953 ) — 25,811 3,825 (93,317 ) Net increase (decrease) in cash 16,049 (15,745 ) 4,535 — 4,839 Cash at beginning of period 65,791 (20,147 ) — — 45,644 Cash at end of period $ 81,840 $ (35,892 ) $ 4,535 $ — $ 50,483

Quarterly Financial Data (una36

Quarterly Financial Data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Information	The following are summarized quarterly financial data for the years ended December 31, 2015 and 2014 : Quarter (in thousands, except per share amounts) 1st 2nd 3rd 4th 2015 Oil and natural gas revenues $ 86,320 $ 93,742 $ 83,526 $ 64,743 Operating loss (1) (313,618 ) (421,465 ) (363,975 ) (240,817 ) Net loss (2) $ (318,112 ) $ (454,155 ) $ (354,519 ) $ (65,595 ) Basic loss per share: Net loss $ (1.17 ) $ (1.67 ) $ (1.30 ) $ (0.24 ) Weighted average shares 271,522 271,549 273,348 277,995 Diluted loss per share: Net loss $ (1.17 ) $ (1.67 ) $ (1.30 ) $ (0.24 ) Weighted average shares 271,522 271,549 273,348 277,995 2014 Oil and natural gas revenues $ 198,472 $ 182,966 $ 151,042 $ 127,789 Operating income 57,423 43,312 22,799 3,341 Net income (loss) $ (4,606 ) $ 2,293 $ 41,569 $ 81,413 Basic earnings (loss) per share: Net income (loss) $ (0.02 ) $ 0.01 $ 0.15 $ 0.30 Weighted average shares 260,716 270,492 270,631 271,053 Diluted earnings (loss) per share: Net income (loss) $ (0.02 ) $ 0.01 $ 0.15 $ 0.30 Weighted average shares 260,716 271,226 272,066 271,053 (1) Operating loss for the first, second, third and fourth quarter of 2015 includes $276.3 million , $394.3 million , $339.4 million and $205.3 million , respectively, of impairments of oil and natural gas properties. See "Note 2. Summary of significant accounting policies" for further discussion. (2) Net loss for the fourth quarter of 2015 includes a $193.3 million net gain on restructuring and extinguishment of debt. See "Note 5. Debt" for further discussion.

Supplemental Information Rela37

Supplemental Information Relating To Oil And Natural Gas Producing Activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Costs Incurred In Oil And Natural Gas Property Acquisition, Exploration And Development Activities	Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities: (in thousands, except per unit amounts) Amount 2015: Proved property acquisition costs $ 7,608 Unproved property acquisition costs — Total property acquisition costs 7,608 Development 215,239 Exploration costs (1) 13,306 Lease acquisitions and other 13,017 Capitalized asset retirement costs 881 Depletion per Boe $ 10.32 Depletion per Mcfe $ 1.72 2014: Proved property acquisition costs $ 10,562 Unproved property acquisition costs — Total property acquisition costs 10,562 Development 354,199 Exploration costs (2) 5,906 Lease acquisitions and other 9,681 Capitalized asset retirement costs 576 Depletion per Boe $ 11.42 Depletion per Mcfe $ 1.90 2013: Proved property acquisition costs $ 754,370 Unproved property acquisition costs 232,020 Total property acquisition costs (3) 986,390 Development 231,447 Exploration costs (4) 38,579 Lease acquisitions and other 14,835 Capitalized asset retirement costs 514 Depletion per Boe $ 8.82 Depletion per Mcfe $ 1.47 (1) Exploration costs in 2015 primarily relate to the wells drilled in the Buda formation in South Texas. (2) Exploration costs in 2014 include $5.9 million in the Bossier shale in North Louisiana. (3) Acquisition costs in 2013 include the acquisition of properties in the Haynesville and Eagle Ford shales and our proportionate share of Compass's acquisition of shallow Cotton Valley assets. (4) Exploration costs in 2013 include $29.2 million in the Eagle Ford shale and $9.4 million in the Marcellus shale.
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of our oil and natural gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise. Oil Natural Mmcfe (13) December 31, 2012 5,570 975,966 1,009,386 Purchase of reserves in place (1) 16,022 304,139 400,271 Discoveries and extensions (2) 5,960 49,912 85,672 Revisions of previous estimates: Changes in price 457 276,730 279,472 Other factors (3) (3,219 ) (111,141 ) (130,455 ) Sales of reserves in place (4) (8,224 ) (308,850 ) (358,194 ) Production (1,188 ) (154,779 ) (161,907 ) December 31, 2013 15,378 1,031,977 1,124,245 Purchase of reserves in place (5) — 7,316 7,316 Discoveries and extensions (6) 4,164 70,544 95,528 Revisions of previous estimates: Changes in price 45 168,064 168,334 Other factors (7) 1,737 120,802 131,224 Sales of reserves in place (8) (1,401 ) (118,705 ) (127,111 ) Production (2,236 ) (122,324 ) (135,740 ) December 31, 2014 17,687 1,157,674 1,263,796 Purchase of reserves in place (9) 459 122 2,876 Discoveries and extensions (10) 7,602 152,473 198,085 Revisions of previous estimates: Changes in price (2,821 ) (598,865 ) (615,791 ) Other factors (11) (145 ) 184,641 183,771 Sales of reserves in place (1 ) (1,445 ) (1,451 ) Production (2,342 ) (109,926 ) (123,978 ) December 31, 2015 20,439 784,674 907,308 Estimated Quantities of Proved Developed and Proved Undeveloped Reserves Oil Natural Mmcfe Proved developed: December 31, 2015 12,056 364,932 437,268 December 31, 2014 14,429 504,636 591,210 December 31, 2013 11,274 669,644 737,291 Proved undeveloped: December 31, 2015 8,383 419,742 470,040 December 31, 2014 3,258 653,038 672,586 December 31, 2013 4,104 362,333 386,954 (1) Purchases of reserves in place include 115.7 Bcfe in the Eagle Ford shale, 260.0 Bcfe in the Haynesville shale, and 24.6 Bcfe for our proportionate share of Compass's acquisition of shallow Cotton Valley assets in East Texas/North Louisiana. (2) New discoveries and extensions in 2013 include 36.5 Bcfe in the Eagle Ford shale, 33.6 Bcfe in the Marcellus shale, 10.2 Bcfe in the Haynesville shale, 3.9 Bcfe for conventional properties held by Compass in the Permian Basin, and 1.5 Bcfe for shale properties in the Permian Basin. (3) Total revisions due to Other factors were downward revisions primarily in the Haynesville shale as a result of operational matters including scaling, liquid loading due to high-line pressure and the impact of drainage on new wells drilled directly offset to the unit wells. (4) Sales of reserves in place in 2013 include 327.6 Bcfe as a result of our contribution of properties to Compass and 30.6 Bcfe from the sale of undeveloped properties in the Eagle Ford in connection with the Participation Agreement. (5) Purchases of reserves in place in 2014 consist primarily of our acquisition of certain proved developed producing properties in the Shelby area of East Texas. (6) New discoveries and extensions in 2014 included 48.7 Bcfe in the Haynesville shale, 26.1 Bcfe in the Eagle Ford Shale and 19.7 Bcfe in the Bossier shale. The discoveries and extensions within the Haynesville and Bossier shales primarily related to our development of properties within the Shelby area of East Texas. (7) Total revisions due to Other factors include upward revisions of approximately 67.1 Bcfe in the Shelby area, approximately 45.9 Bcfe in the Appalachia region, and approximately 5.8 Bcfe in the Holly area. The upward revisions were primarily due to improved well performance resulting from enhanced well designs and completion techniques. (8) Sales of reserves in place in 2014 consist primarily of the sale of our entire interest in Compass. (9) Purchases of reserves in place include the acquisition of certain proved developed producing properties in the Eagle Ford shale in connection with the Participation Agreement. (10) New discoveries and extensions in 2015 include 84.9 Bcfe and 41.0 Bcfe in the Haynesville shale and Bossier shale, respectively, related to our development of properties within the Shelby area of East Texas. Additionally, extensions and discoveries in 2015 included 24.7 Bcfe in the in the Haynesville shale related to the development of the Holly area in North Louisiana and 47.5 Bcfe in the Eagle Ford shale. (11) Total revisions due to Other factors include upward revisions of approximately 152.2 Bcfe in the North Louisiana Holly area and are primarily due to modifications in the well design to incorporate more proppant and longer laterals. The upward revisions also included 36.7 Bcfe from our East Texas region primarily due to strong results in both the Haynesville and Bossier shales based on our enhanced completion methods. The upward revisions also reflect a reduction in capital costs and operating expenses. (12) Beginning in 2015, we began reporting our NGLs as a component of natural gas as NGLs are not considered to be significant. Primarily all of our prior period NGLs were associated with properties owned by Compass, which EXCO divested in 2014. Prior period information has been conformed to be consistent with current period information. (13) The above reserves do not include our equity interest in OPCO, which was not significant in any period presented.
Standardized Measure Of Discounted Future Net Cash Flows	We have summarized the Standardized Measure related to our proved oil and natural gas reserves. We have based the following summary on a valuation of Proved Reserves using discounted cash flows based on prices as prescribed by the SEC, costs and economic conditions and a 10% discount rate. The additions to Proved Reserves from the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, the information presented below should not be viewed as an estimate of the fair value of our oil and natural gas properties, nor should it be indicative of any trends. (in thousands) Amount Year ended December 31, 2015: Future cash inflows $ 2,684,362 Future production costs 1,280,795 Future development costs 641,768 Future income taxes — Future net cash flows 761,799 Discount of future net cash flows at 10% per annum 359,666 Standardized measure of discounted future net cash flows $ 402,133 Year ended December 31, 2014: Future cash inflows $ 6,097,207 Future production costs 2,094,796 Future development costs 1,124,873 Future income taxes — Future net cash flows 2,877,538 Discount of future net cash flows at 10% per annum 1,334,951 Standardized measure of discounted future net cash flows $ 1,542,587 Year ended December 31, 2013: Future cash inflows $ 5,176,030 Future production costs 2,207,230 Future development costs 904,116 Future income taxes — Future net cash flows 2,064,684 Discount of future net cash flows at 10% per annum 812,411 Standardized measure of discounted future net cash flows $ 1,252,273
Principal Sources Of Change In The Standardized Measure	The following are the principal sources of change in the Standardized Measure: (in thousands) Amount Year ended December 31, 2015: Sales and transfers of oil and natural gas produced $ (152,937 ) Net changes in prices and production costs (1,438,490 ) Extensions and discoveries, net of future development and production costs 99,818 Development costs during the period 109,895 Changes in estimated future development costs 407,780 Revisions of previous quantity estimates (232,325 ) Sales of reserves in place (1,632 ) Purchase of reserves in place 6,892 Accretion of discount before income taxes 126,533 Changes in timing and other (65,988 ) Net change in income taxes — Net change $ (1,140,454 ) Year ended December 31, 2014: Sales and transfers of oil and natural gas produced $ (464,369 ) Net changes in prices and production costs 279,944 Extensions and discoveries, net of future development and production costs 196,796 Development costs during the period 189,155 Changes in estimated future development costs (254,737 ) Revisions of previous quantity estimates 412,296 Sales of reserves in place (148,226 ) Purchase of reserves in place 13,507 Accretion of discount before income taxes 125,227 Changes in timing and other (59,279 ) Net change in income taxes — Net change $ 290,314 Year ended December 31, 2013: Sales and transfers of oil and natural gas produced $ (450,415 ) Net changes in prices and production costs 582,725 Extensions and discoveries, net of future development and production costs 197,223 Development costs during the period 55,196 Changes in estimated future development costs (251,484 ) Revisions of previous quantity estimates 98,283 Sales of reserves in place (315,758 ) Purchase of reserves in place 604,366 Accretion of discount before income taxes 69,615 Changes in timing and other (33,625 ) Net change in income taxes — Net change $ 556,126
Costs Not Subject To Amortization	The following table summarizes the categories of costs comprising the amount of unproved properties not subject to amortization by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The majority of the evaluation activities are expected to be completed within one to seven years. (in thousands) Total 2015 2014 2013 2012 and Property acquisition costs $ 75,019 $ 11,121 $ 7,862 $ 12,403 $ 43,633 Exploration and development 12,100 12,100 — — — Capitalized interest 28,258 8,464 8,604 5,384 5,806 Total $ 115,377 $ 31,685 $ 16,466 $ 17,787 $ 49,439

Organization And Basis Of Pre38

Organization And Basis Of Presentation (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015
OPCO [Member]
Working interest in equity investment	0.50%
Percentage of ownership interest	50.00%
East Texas/North Louisiana JV [Member]
Ownership percentage in joint venture	50.00%
Appalachia JV [Member]
Ownership percentage in joint venture	50.00%
Proportional working interest	49.75%

Summary Of Significant Accoun39

Summary Of Significant Accounting Policies (Narrative) (Details) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)$ / bblrevenue_reported_baseagreement$ / MMBTU	Dec. 31, 2014USD ($)$ / bbl$ / MMBTU	Dec. 31, 2013USD ($)$ / bbl$ / MMBTU	Oct. 31, 2014
Summary Of Significant Accounting Policies [Line Items]
Unproved oil and natural gas properties and development cost	$ 115,377				$ 115,377	$ 276,025
Impairment of unproved costs to proved properties					$ 88,100	$ 0	$ 1,000
Reference prices per mmbtu of natural gas | $ / MMBTU					2.59	4.35	3.67
Reference prices per bbl of oil | $ / bbl					50.28	94.99	96.78
Impairment of oil and natural gas properties	205,300	$ 339,400	$ 394,300	$ 276,300	$ 1,215,370	$ 0	$ 108,546
Number of Agreements to Sell Oil and Gas | agreement					2
Number of Revenue Reporting Bases | revenue_reported_base					2
Gathering and transportation					$ 99,321	101,574	100,645
Personnel costs capitalized to full cost pool	$ 10,600				10,600	15,800	18,200
Capitalized equity-based compensation					3,428	5,498	7,288
Overhead charges billed to working interest owners					13,100	13,500	10,500
Overhead charges classified as oil and natural gas production costs					5,700	6,400	5,800
Reduced general and administrative expenses					$ 15,900	24,700	$ 26,800
Deferred Tax Assets, Net of Valuation Allowance, Current						$ 35,900
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Evaluation period for oil and natural gas cost					1 year
Estimated useful lives, years					3 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Evaluation period for oil and natural gas cost					7 years
Estimated useful lives, years					15 years
Chesapeake Energy Marketing Inc. [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of consolidated revenues	38.00%				38.00%	31.00%	14.00%
B G Energy Merchants L L C [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of consolidated revenues	20.00%				20.00%	34.00%	48.00%
Compass [Member]
Summary Of Significant Accounting Policies [Line Items]
Ownership percentage in joint venture							25.50%	25.50%

Summary Of Significant Accoun40

Summary Of Significant Accounting Policies (Reconciliation Of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of period		$ 36,755	$ 42,954	$ 61,864
Liabilities incurred during the period		881	576	514
Revisions in estimated assumptions		3,215	0	1,268
Liabilities settled during the period		(293)	(33)	(187)
Adjustment to liability due to acquisitions		180	107	5,566
Adjustment to liability due to divestitures (1)	[1]	(1,367)	(9,539)	(28,585)
Accretion of discount		2,277	2,690	2,514
Asset retirement obligations at end of period		41,648	36,755	42,954
Less current portion		845	1,769	191
Long-term portion		$ 40,803	34,986	42,763
Compass [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Adjustment to liability due to divestitures (1)			$ (9,400)	$ (28,300)
[1]	For the year ended December 31, 2014, the adjustment to liability due to divestitures consisted primarily of $9.4 million from the sale of our interest in Compass. For the year ended December 31, 2013, the adjustment to liability due to divestitures consisted primarily of $28.3 million from the contribution of our certain conventional assets to Compass.

Acquisitions, Divestitures An41

Acquisitions, Divestitures And Other Significant Events (Narrative) MMBTU in Thousands, $ in Thousands	Mar. 11, 2015USD ($)wells	Oct. 31, 2014USD ($)	Sep. 30, 2015wells	Dec. 31, 2015USD ($)$ / MMBTUwellsMMBTU	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)wellsacres	Dec. 31, 2012USD ($)
Business Acquisition [Line Items]
Decrease to capitalized costs		$ 87,400
Payments to Acquire Oil and Gas Property and Equipment				$ 7,608	$ 10,790	$ 976,714
Oil and Gas Property, Full Cost Method, Gross				3,070,430	3,852,073
Asset Retirement Obligation				41,648	36,755	42,954	$ 61,864
Equity Method Investment, Other than Temporary Impairment				$ 11,000		86,800
Compass [Member]
Business Acquisition [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment		$ 118,800				$ 574,800
Ownership percentage in joint venture		25.50%				25.50%
Net Assets		$ 31,400
HGI's economic interest in Compass						74.50%
Gain on Disposition of Property Plant Equipment						$ 186,400
Reduction in goodwill						55,100
Payments to Acquire Oil and Gas Property and Equipment						130,700
Acreage transaction [Member]
Business Acquisition [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment					$ 68,200	$ 37,900
Sale of undivided interest percentage						50.00%
Participation Agreement [Member]
Business Acquisition [Line Items]
Period of Production, Productive Wells, Threshold to Offer Purchase				1 year
Number of Productive Wells Acquired, Gross | wells	3
Number of Productive Wells Acquired, Net | wells	1.4
Business Combination, Consideration Transferred	$ 7,600
Number of Productive Wells Not Accepted, Gross | wells			10
Number of Productive Wells Not Accepted, Net | wells			5.2
Number of Productive Wells in Dispute, Gross | wells				21
Number of Productive Wells in Dispute, Net | wells				10.3
Business combination, Consideration in Dispute				$ 42,700
Haynesville [Member]
Business Acquisition [Line Items]
Acquisition purchase price						$ 281,101
Wells operated by EXCO | wells						170
Net acres acquired on wells operated by EXCO | acres						5,500
Wells operated by Chesapeake | wells						11
Net acres acquired on Chesapeake operated wells | acres						4,000
Percent of assets subject to preferential right						50.00%
Oil and Gas Property, Full Cost Method, Gross						$ 285,200
Asset Retirement Obligation						610
Eagle Ford [Member]
Business Acquisition [Line Items]
Acquisition purchase price						$ 661,845
Wells operated by Chesapeake | wells						120
Net acres acquired on Chesapeake operated wells | acres						53,500
Oil and Gas Property, Full Cost Method, Gross						$ 665,500
Asset Retirement Obligation						3,060
KKR [Member]
Business Acquisition [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment						$ 130,900
Interest sold in the undeveloped acreage						50.00%
Azure [Member]
Business Acquisition [Line Items]
Ownership percentage in cost method investment						4.00%
Cost Method Investments						$ 13,400
Cost-method Investments, Other than Temporary Impairment				$ 2,900
TGGT [Member]
Business Acquisition [Line Items]
Equity Method Investment, Net Sales Proceeds						$ 240,200
Combined EXCO and BG Group's 100% interest [Member]
Business Acquisition [Line Items]
Minimum volume commitment per day of natural gas production | MMBTU				600
Amount per mmbtu multiplied by shortfall to the minimum volume commitment | $ / MMBTU				0.40
Percent credit to EXCO and BG Group for excess volumes delivered				25.00%
Compass Production Partners Credit Agreement [Member] | Compass [Member]
Business Acquisition [Line Items]
Outstanding indebtedness		$ 83,200

Acquisitions, Divestitures An42

Acquisitions, Divestitures And Other Significant Events (Purchase Price Allocation) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Unproved oil and natural gas properties	$ 115,377	$ 276,025
Accounts Payable and Accrued Liabilities, Current	(85,254)	(110,211)
Revenues and royalties payable	(106,163)	(152,651)
Asset Retirement Obligation	$ (41,648)	$ (36,755)	$ (42,954)	$ (61,864)
Haynesville [Member]
Business Acquisition [Line Items]
Unproved oil and natural gas properties			2,319
Proved developed and undeveloped oil and natural gas properties			282,918
Accounts Payable and Accrued Liabilities, Current			0
Revenues and royalties payable			(3,526)
Asset Retirement Obligation			(610)
Total purchase price			281,101
Eagle Ford [Member]
Business Acquisition [Line Items]
Unproved oil and natural gas properties			227,869
Proved developed and undeveloped oil and natural gas properties			437,616
Accounts Payable and Accrued Liabilities, Current			(580)
Revenues and royalties payable			0
Asset Retirement Obligation			(3,060)
Total purchase price			$ 661,845

Derivative Financial Instrume43

Derivative Financial Instruments (Narrative) (Details) bbl in Thousands, MMBTU in Thousands	12 Months Ended
	Dec. 31, 2015MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2014MMBTUbbl
Derivative [Line Items]
Percentage of derivative instruments to equivalent production	68.00%	69.00%
2016 [Member] | Oil [Member]
Derivative [Line Items]
Average forward NYMEX prices | $ / bbl	40.97
2016 [Member] | Natural Gas [Member]
Derivative [Line Items]
Average forward NYMEX prices | $ / MMBTU	2.50
2017 [Member] | Natural Gas [Member]
Derivative [Line Items]
Average forward NYMEX prices | $ / MMBTU	2.79
2018 [Member] | Natural Gas [Member]
Derivative [Line Items]
Average forward NYMEX prices | $ / MMBTU	2.91
Swap [Member] | Oil [Member]
Derivative [Line Items]
Investment Contract Volume | bbl		1,095
Swap [Member] | Natural Gas [Member]
Derivative [Line Items]
Three way collar converted to swap - natural gas volume		10,980
Natural gas volume		42,888
Swap [Member] | 2016 [Member] | Oil [Member]
Derivative [Line Items]
Investment Contract Volume | bbl	915
Swap [Member] | 2016 [Member] | Natural Gas [Member]
Derivative [Line Items]
Average price of fixed-price swap converted | $ / MMBTU	2.78
Natural gas volume	34,770
Swap [Member] | 2017 [Member] | Natural Gas [Member]
Derivative [Line Items]
Natural gas volume	10,950
Swap [Member] | 2018 [Member] | Natural Gas [Member]
Derivative [Line Items]
Natural gas volume	3,650
Basis Swap [Member] | Oil [Member]
Derivative [Line Items]
Investment Contract Volume | bbl		91
Call Option [Member] | Oil [Member]
Derivative [Line Items]
Investment Contract Volume | bbl		365
Call Option [Member] | Natural Gas [Member]
Derivative [Line Items]
Natural gas volume		20,075
Three Way Collars [Member] | Natural Gas [Member]
Derivative [Line Items]
Natural gas volume		38,355

Derivative Financial Instrume44

Derivative Financial Instruments (Fair Value Of Derivative Financial Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Derivative financial instruments - Current assets	$ 39,499	$ 97,278
Derivative financial instruments - Long-term assets	6,109	2,138
Derivative financial instruments - Current liabilities	(16)	(892)
Derivative financial instruments - Long-term liabilities	0	0
Net derivative financial instruments	$ 45,592	$ 98,524

Derivative Financial Instrume45

Derivative Financial Instruments (Effect Of Derivative Financial Instruments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Gain (Loss) on derivative financial instruments	$ 75,869	$ 87,665	$ (320)

Derivative Financial Instrume46

Derivative Financial Instruments (Fair Value Of Oil And Natural Gas Derivative Financial Instruments) (Details) bbl in Thousands, MMBTU in Thousands, $ in Thousands	Dec. 31, 2015USD ($)MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2014USD ($)MMBTUbbl
Derivatives, Fair Value [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	$ 45,592	$ 98,524
Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	27,003
Oil [Member]
Derivatives, Fair Value [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	$ 18,589
Swap [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu | MMBTU		42,888
Swap [Member] | Oil [Member]
Derivatives, Fair Value [Line Items]
Volume (oil) | bbl		1,095
Swap [Member] | 2016 [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu | MMBTU	34,770
Weighted average strike price per Mmbtu/Bbl | $ / MMBTU	3.09
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	$ 20,894
Swap [Member] | 2016 [Member] | Oil [Member]
Derivatives, Fair Value [Line Items]
Volume (oil) | bbl	915
Weighted average strike price per Mmbtu/Bbl | $ / bbl	61.89
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	$ 18,589
Swap [Member] | 2017 [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu | MMBTU	10,950
Weighted average strike price per Mmbtu/Bbl | $ / MMBTU	3.28
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	$ 5,279
Swap [Member] | 2018 [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu | MMBTU	3,650
Weighted average strike price per Mmbtu/Bbl | $ / MMBTU	3.15
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	$ 830

Debt (Narrative) (Details)

Debt (Narrative) (Details) $ in Thousands	1 Months Ended	12 Months Ended			72 Months Ended
	Feb. 29, 2016USD ($)	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)	Dec. 31, 2015USD ($)	Feb. 25, 2016USD ($)	Nov. 25, 2015USD ($)	Nov. 04, 2015USD ($)	Oct. 26, 2015USD ($)	Oct. 19, 2015USD ($)	Mar. 31, 2015
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt		$ 28,200
Principal amount		1,148,333			$ 1,148,333
Troubled Debt Restructuring, Debtor, Current Period, Gain (Loss) on Restructuring, Net of Tax		165,100
Repayments of Unsecured Debt		12,008	$ 0	$ 0
Common stock repurchased to date		$ 17	$ 136		$ 7,632
Shares paid for tax withholding for share based compensation | shares		16,621	38,821
Exco Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Current ratio, numerator		1
Current ratio, denominator		1
Interest Coverage Ratio		1.25			1.25
Senior Secured Indebtedness Ratio											2.5
Stock Repurchase Program, Authorized Amount		$ 200,000			$ 200,000
Minimum security interest as percentage of Engineered Value		80.00%
Maximum percentage of production for derivatives coverage		100.00%
Maximum Percentage Of Forecasted Production from Total Proved Reserves For Any Month During The Third Year		90.00%
Maximum Percentage Of Forecasted Production from Total Proved Reserves For Any Month During The Fourth Year		85.00%
Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, principal outstanding		$ 158,015	$ 750,000		$ 158,015
Debt instrument, interest rate		7.50%			7.50%
Debt Instrument, Repurchase Amount		$ 40,800			$ 40,800
Repayments of Unsecured Debt		12,000
Debt Instrument, Amount Exchanged		551,200			551,200
Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, principal outstanding		$ 222,826	500,000		$ 222,826
Debt instrument, interest rate		8.50%			8.50%
Principal amount		$ 222,826			$ 222,826
Debt Instrument, Issued Price, Percentage		100.00%			100.00%
Debt Instrument, Amount Exchanged		$ 277,200			$ 277,200
Revolving Credit Facility [Member] | Exco Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Outstanding indebtedness		67,492	202,492		67,492
Borrowing base		375,000			375,000					$ 600,000
Unused borrowing base		$ 300,900			$ 300,900
Line of credit facility, maturity date		Jul. 31, 2018
Line of credit facility, interest rate at period end		3.30%			3.30%
Maximum principal amount allowed		$ 900,000			$ 900,000
Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | Exco Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.25%
Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member] | Exco Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		3.25%
Revolving Credit Facility [Member] | Alternate Base Rate (ABR) [Member] | Minimum [Member] | Exco Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.25%
Revolving Credit Facility [Member] | Alternate Base Rate (ABR) [Member] | Maximum [Member] | Exco Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.25%
Subsequent Event [Member]
Debt Instrument [Line Items]
Repayments of Unsecured Debt	$ 6,700
Subsequent Event [Member] | Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, principal outstanding						$ 148,500
Debt Instrument, Repurchase Amount	9,500
Repayments of Unsecured Debt	2,200
Subsequent Event [Member] | Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, principal outstanding						$ 182,900
Debt Instrument, Repurchase Amount	39,900
Repayments of Unsecured Debt	$ 4,500
Senior Notes [Member] | Fairfax Term Loan [Member]
Debt Instrument [Line Items]
Debt instrument, principal outstanding		$ 300,000			300,000
Debt instrument, interest rate									12.50%
Principal amount		300,000	$ 0		300,000
Debt Instrument, Covenant, Maximum Priority Borrowing Capacity		500,000			500,000
Debt Instrument, Covenant, Maximum Borrowing Capacity for all Second Liens of Indebtedness		400,000			400,000
Debt Instrument, Covenant, Priority Borrowing Capacity		375,000			375,000
Senior Notes [Member] | Exchange Term Loan [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate									12.50%
Principal amount		$ 400,000			$ 400,000			$ 108,700	$ 291,300
Debt Instrument, Covenant, Maximum Percentage of Modified Adjusted Consolidated Net Tangible Assets		30.00%			30.00%
Debt Instrument, Covenant, Maximum Borrowing Capacity for all Second Liens of Indebtedness		$ 700,000			$ 700,000
Debt Instrument, Covenant, Coverage Ratio, Maximum for Unsecured Borrowings		2.25			2.25
Senior Notes [Member] | Second Lien Term Loans [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate		12.50%			12.50%
Senior Notes [Member] | Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, principal outstanding		$ 157,083			$ 157,083
Senior Notes [Member] | Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, principal outstanding		$ 222,826			$ 222,826
Line of Credit [Member] | Exco Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity							$ 1,200,000

Debt (Schedule Of Long-Term Deb

Debt (Schedule Of Long-Term Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Nov. 04, 2015	Oct. 26, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Principal amount	$ 1,148,333
Deferred financing costs, net	18,294			$ 16,019
Total debt	1,370,279			1,430,516
Less amounts due within one year	50,000			0
Total debt due after one year	1,320,279			1,430,516
Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Senior Notes	158,015			750,000
Unamortized discount on 2018 Notes	(932)			(5,957)
Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Principal amount	222,826
Senior Notes	222,826			500,000
Revolving Credit Facility [Member] | Exco Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Revolving credit facility under credit agreement	67,492			202,492
Senior Notes [Member] | Exchange Term Loan [Member]
Debt Instrument [Line Items]
Principal amount	400,000	$ 108,700	$ 291,300
Exchange Term Loan	641,172			0
Senior Notes [Member] | Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Senior Notes	157,083
Senior Notes [Member] | Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	222,826
Senior Notes [Member] | Fairfax Term Loan [Member]
Debt Instrument [Line Items]
Principal amount	300,000			$ 0
Senior Notes	$ 300,000

Debt (Detailed Summary) (Detail

Debt (Detailed Summary) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Nov. 04, 2015	Oct. 26, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Deferred reduction in carrying value	$ 241,172
Debt Instrument, Unamortized Discount and Deferred Financing Costs	19,226
Principal amount	1,148,333
Deferred financing costs, net	18,294			$ 16,019
Total debt	1,370,279			1,430,516
Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Senior Notes	158,015			750,000
Unamortized discount/deferred financing costs	932			5,957
Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	222,826			500,000
Principal amount	222,826
Secured Debt [Member] | Exchange Term Loan [Member]
Debt Instrument [Line Items]
Senior Notes	641,172
Deferred reduction in carrying value	241,172
Senior Notes [Member] | Exchange Term Loan [Member]
Debt Instrument [Line Items]
Principal amount	400,000	$ 108,700	$ 291,300
Senior Notes [Member] | Fairfax Term Loan [Member]
Debt Instrument [Line Items]
Senior Notes	300,000
Principal amount	300,000			0
Senior Notes [Member] | Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Senior Notes	157,083
Senior Notes [Member] | Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	222,826
Revolving Credit Facility [Member] | Exco Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Revolving credit facility under credit agreement	$ 67,492			$ 202,492

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 25, 2016
Debt Instrument [Line Items]
Impairment of unproved costs to proved properties	$ 88,100	$ 0	$ 1,000
Equity Method Investment, Other than Temporary Impairment	11,000		$ 86,800
Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	43,170	558,750
Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	48,376	373,500
Exchange Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	278,000
Fairfax Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	208,500
Level 1 [Member] | Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	43,170	558,750
Level 1 [Member] | Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	48,376	373,500
Level 1 [Member] | Exchange Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	0
Level 1 [Member] | Fairfax Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	0
Level 1 [Member] | Subsequent Event [Member] | Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure				$ 25,200
Level 1 [Member] | Subsequent Event [Member] | Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure				37,600
Fair Value, Inputs, Level 2 [Member] | Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 2 [Member] | Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	0	$ 0
Fair Value, Inputs, Level 2 [Member] | Exchange Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	278,000
Fair Value, Inputs, Level 2 [Member] | Fairfax Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	$ 208,500
Fair Value, Inputs, Level 2 [Member] | Subsequent Event [Member] | Exchange Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure				178,000
Fair Value, Inputs, Level 2 [Member] | Subsequent Event [Member] | Fairfax Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure				$ 133,500

Fair Value Measurements (Summar

Fair Value Measurements (Summary Of Estimated Fair Value Of Derivative Financial Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Oil and natural gas derivative financial instruments	$ 45,592	$ 98,524
Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Oil and natural gas derivative financial instruments	0	0
Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Oil and natural gas derivative financial instruments	45,592	98,524
Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Oil and natural gas derivative financial instruments	$ 0	$ 0

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule Of Estimated Fair Value Of Other Financial Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Senior Unsecured Notes due 2018 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$ 43,170	$ 558,750
Senior Unsecured Notes due 2018 [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	43,170	558,750
Senior Unsecured Notes due 2018 [Member] | Level 2 [Member]
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 [Member] | Level 3 [Member]
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 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	48,376	373,500
Senior Unsecured Notes due 2022 [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	48,376	373,500
Senior Unsecured Notes due 2022 [Member] | Level 2 [Member]
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 [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0	$ 0
Exchange Term Loan [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	278,000
Exchange Term Loan [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0
Exchange Term Loan [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	278,000
Exchange Term Loan [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0
Fairfax Term Loan [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	208,500
Fairfax Term Loan [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0
Fairfax Term Loan [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	208,500
Fairfax Term Loan [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$ 0

Commitments And Contingencies53

Commitments And Contingencies (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Rental expenses	$ 3.4	$ 5.1	$ 5.9

Commitments And Contingencies54

Commitments And Contingencies (Schedule Of Future Minimum Rental Payments Under Operation Leases) (Details) $ in Thousands	Dec. 31, 2015USD ($)
Long-term Purchase Commitment [Line Items]
2,016	$ 154,120
2,017	137,040
2,018	122,815
2,019	81,741
2,020	51,640
Thereafter	137,614
Total	684,970
Gathering and Firm Transportation Services [Member]
Long-term Purchase Commitment [Line Items]
2,016	120,414
2,017	120,085
2,018	116,365
2,019	76,285
2,020	48,148
Thereafter	135,943
Total	617,240
Other Fixed Commitments [Member]
Long-term Purchase Commitment [Line Items]
2,016	13,253
2,017	5,443
2,018	3,210
2,019	2,403
2,020	1,932
Thereafter	1,599
Total	27,840
Drilling Contracts [Member]
Long-term Purchase Commitment [Line Items]
2,016	14,997
2,017	7,284
2,018	0
2,019	0
2,020	0
Thereafter	0
Total	22,281
Operating Leases And Other [Member]
Long-term Purchase Commitment [Line Items]
2,016	5,456
2,017	4,228
2,018	3,240
2,019	3,053
2,020	1,560
Thereafter	72
Total	$ 17,609

Commitments And Contingencies55

Commitments And Contingencies (Schedule of Firm Transportation Services and Gathering Services) (Details) Mcf in Millions	Dec. 31, 2015Mcf
Firm Transportation Services [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
2,016	270
2,017	269
2,018	269
2,019	269
2,020	177
Thereafter	596
Total	1,850
Gathering Services [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
2,016	110
2,017	110
2,018	100
2,019	0
2,020	0
Thereafter	0
Total	320

Employee Benefit Plans (Details

Employee Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
General Discussion of Pension and Other Postretirement Benefits [Abstract]
Matched employee contribution in percentage	100.00%
Contributions by employer	$ 5.2	$ 7.1	$ 8.8

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net income (loss)	$ (65,595)	[1]	$ (354,519)	[1]	$ (454,155)	[1]	$ (318,112)	[1]	$ 81,413	$ 41,569	$ 2,293	$ (4,606)	$ (1,192,381)	$ 120,669	$ 22,204
Weighted average common shares outstanding	277,995		273,348		271,549		271,522		271,053	270,631	270,492	260,716	273,621	268,258	215,011
Net income (loss) per basic common share	$ (0.24)		$ (1.30)		$ (1.67)		$ (1.17)		$ 0.30	$ 0.15	$ 0.01	$ (0.02)	$ (4.36)	$ 0.45	$ 0.10
Dilutive effect of warrants													0	0	0
Weighted average common and common equivalent shares outstanding	277,995		273,348		271,549		271,522		271,053	272,066	271,226	260,716	273,621	268,376	230,912
Net income (loss) per diluted common share	$ (0.24)		$ (1.30)		$ (1.67)		$ (1.17)		$ 0.30	$ 0.15	$ 0.01	$ (0.02)	$ (4.36)	$ 0.45	$ 0.10
Stock Options [Member]
Dilutive effect of stock equivalents													0	0	0
Restricted Stock [Member]
Dilutive effect of stock equivalents													0	118	420
Subscription Rights (Member)
Dilutive effect of stock equivalents													0	0	15,481
[1]	Net loss for the fourth quarter of 2015 includes a $193.3 million net gain on restructuring and extinguishment of debt. See "Note 5. Debt" for further discussion.

Earnings Per Share (Details Tex

Earnings Per Share (Details Textual) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	39,544,192	14,316,409	55,524,191

Equity-based compensation (Narr

Equity-based compensation (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	Jul. 01, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jun. 11, 2013	Dec. 31, 2015	Oct. 05, 2011	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Capitalized equity-based compensation		$ 3,428	$ 5,498	$ 7,288
Shares authorized for issuance		45,500,000				45,500,000
Shares available for grant		17,773,172	19,763,916			17,773,172
Total share-based compensation to be recognized on unvested awards		$ 7,900				$ 7,900
Total share-based compensation to be recognized, weighted average period (years)		1 year 11 months
Total tax benefit		$ 0	$ 0	$ 0
Weighted average remaining life, years		3 years 5 months
Stock options vesting percentage		25.00%
Award Vesting Period		3 years
Weighted average grant date fair value of stock options granted			$ 2.23	$ 3.53
Total intrinsic value of stock options exercised			$ 0	$ 200
Vesting percentage		25.00%
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Option Contractual Term Life		5 years
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Option Contractual Term Life		10 years
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation current granted counts		1
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		4,541,570	1,877,929	1,928,314		4,541,570		2,806,365
Share-based compensation current granted counts					2.1	1.74	1.17
Shares of common stock granted		4,414,470	1,339,782	556,700
Restricted Stock [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Vesting Period		2 years
Restricted Stock [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Vesting Period		5 years
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		2,115,000	0			2,115,000
Other Liabilities		$ 600				$ 600
Capitalized equity-based compensation		$ 200
Shares of common stock granted		2,496,250
Performance Shares [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vesting Percentage	0.00%
Performance Shares [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vesting Percentage	200.00%
Target Price Awards [Member] | Market-based restricted stock awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		290,200	401,400			290,200
Shares of common stock granted		0
$10.00 market-based restricted stock award [Member] | Market-based restricted stock awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares expected to vest		145,100
Number of days required for awards to vest		30 days
Price per share required for market-based restricted stock award to vest		$ 10
$15.00 market-based restricted stock award [Member] | Market-based restricted stock awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares expected to vest		145,100
Number of days required for awards to vest		30 days
Price per share required for market-based restricted stock award to vest		$ 15
Based on Total Shareholder Return [Member] | Market-based restricted stock awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		546,878	716,150			546,878
Shares of common stock granted		0
Based on Total Shareholder Return [Member] | Market-based restricted stock awards [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage		0.00%
Based on Total Shareholder Return [Member] | Market-based restricted stock awards [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage		200.00%

Equity-based compensation (Stoc

Equity-based compensation (Stock Option Activity) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Stock options, Options outstanding	10,150,518	11,711,743	14,015,795
Stock options, Granted	0	141,525	2,886,500
Stock options, Forfeitures	(4,538,858)	(1,700,250)	(4,969,877)
Stock options, Exercised	0	(2,500)	(220,675)
Stock options, Options outstanding	5,611,660	10,150,518	11,711,743
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]
Weighted average exercise price per share, Options outstanding	$ 12.58	$ 12.69	$ 13.20
Weighted average exercise price per share, Granted	0	5.24	7.48
Weighted average exercise price per share, Forfeitures	12.30	12.71	11.32
Weighted average exercise price per share, Exercised	0	5.22	7.66
Weighted average exercise price per share, Options outstanding	$ 12.81	$ 12.58	$ 12.69
Weighted average remaining terms, Options outstanding (in years)	3 years 5 months
Aggregate intrinsic value, Options outstanding	$ 0
Stock options, Options exercisable	5,276,336
Weighted average exercise price per share, Options exercisable	$ 13.18
Weighted average remaining terms, Options exercisable (in years)	3 years 2 months
Aggregate intrinsic value, Options exercisable	$ 0

Equity-based compensation (Fair

Equity-based compensation (Fair Value Option Assumptions) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life		7 years 6 months
Risk-free rate of return, minimum		2.25%	0.48%
Risk-free rate of return, maximum		2.61%	2.49%
Volatility, minimum		59.46%	49.47%
Volatility, maximum		59.61%	59.86%
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life			3 years 9 months 18 days
Dividend yield		3.36%	2.27%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life			7 years 6 months
Dividend yield		4.34%	3.87%
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free rate of return, minimum	0.85%
Risk-free rate of return, maximum	1.18%
Volatility, minimum	62.58%
Volatility, maximum	95.79%
Dividend yield	0.00%

Equity-based compensation (Rest

Equity-based compensation (Restricted Stock Activity and PSU activity) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested shares outstanding at beginning of period	0
Shares, Granted	2,496,250
Shares, Vested	0
Shares, Forfeited	(381,250)
Non-vested shares outstanding at end of period	2,115,000	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted average grant date fair value per share at beginning of period	$ 0
Granted	1.45
Vested	0
Forfeited	1.25
Weighted average grant date fair value per share at end of period	$ 2.39	$ 0
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested shares outstanding at beginning of period	1,877,929	1,928,314	2,806,365
Shares, Granted	4,414,470	1,339,782	556,700
Shares, Vested	(847,446)	(1,109,866)	(832,706)
Shares, Forfeited	(903,383)	(280,301)	(602,045)
Non-vested shares outstanding at end of period	4,541,570	1,877,929	1,928,314
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted average grant date fair value per share at beginning of period	$ 6.40	$ 9.26	$ 10.16
Granted	1.05	5.20	7.15
Vested	6.80	9.79	10.47
Forfeited	3.17	6.89	9.84
Weighted average grant date fair value per share at end of period	$ 1.77	$ 6.40	$ 9.26
Target Price Awards [Member] | Market-based restricted stock awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested shares outstanding at beginning of period	401,400
Shares, Granted	0
Shares, Vested	0
Shares, Forfeited	(111,200)
Non-vested shares outstanding at end of period	290,200	401,400
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted average grant date fair value per share at beginning of period	$ 6.36
Granted	0
Vested	0
Forfeited	6.36
Weighted average grant date fair value per share at end of period	$ 6.36	$ 6.36
Based on Total Shareholder Return [Member] | Market-based restricted stock awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested shares outstanding at beginning of period	716,150
Shares, Granted	0
Shares, Vested	0
Shares, Forfeited	(169,272)
Non-vested shares outstanding at end of period	546,878	716,150
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted average grant date fair value per share at beginning of period	$ 7.33
Granted	0
Vested	0
Forfeited	7.33
Weighted average grant date fair value per share at end of period	$ 7.33	$ 7.33

Equity-based compensation Warra

Equity-based compensation Warrants (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 19, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation related to warrants	$ 3.2
Number of shares issuable			0.25
Estimated fair value (in millions)	$ 37.1
Common Stock, Shares Authorized	780,000,000	350,000,000
Tranche A
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares issuable	15,000,000
Exercise Price	$ 2.75
Estimated fair value per warrant	$ 0.50
Estimated fair value (in millions)	$ 7.5
Term	Apr. 30, 2019
Tranche B
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares issuable	20,000,000
Exercise Price	$ 4
Estimated fair value per warrant	$ 0.50
Estimated fair value (in millions)	$ 10
Term	Mar. 31, 2020
Tranche C
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares issuable	20,000,000
Exercise Price	$ 7
Estimated fair value per warrant	$ 0.48
Estimated fair value (in millions)	$ 9.6
Term	Mar. 31, 2021
Tranche D
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares issuable	25,000,000
Exercise Price	$ 10
Estimated fair value per warrant	$ 0.40
Estimated fair value (in millions)	$ 10
Term	Mar. 31, 2021
Energy Strategic Advisory Services LLC (ESAS) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares issuable	80,000,000
Energy Strategic Advisory Services LLC (ESAS) [Member] | 50th to 74th Percentile of Peer Group [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares issuable	32,000,000
Energy Strategic Advisory Services LLC (ESAS) [Member] | 75th Percentile or Above of Peer Group [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares issuable	80,000,000

Equity-based compensation (Reco

Equity-based compensation (Reconciliation Of Share-Based Compensation Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation [Abstract]
Equity-based compensation expense	$ 7,198	$ 4,962	$ 10,748
Share-based compensation capitalized	3,428	5,498	7,288
Total equity-based compensation	10,626	10,460	18,036
Compensation expense on liability-classified awards (2)	$ 396	$ 0	$ 0

Income Taxes (Components Of Inc

Income Taxes (Components Of Income Tax Provision (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current:
Federal	$ 0	$ 0	$ 0
State	0	0	0
Total current income tax (benefit)	0	0	0
Deferred:
Federal	(414,834)	45,797	25,626
State	(45,009)	18,960	3,239
Valuation allowance	459,843	(64,757)	(28,865)
Total deferred income tax (benefit)	0	0	0
Total income tax (benefit)	0	$ 0	$ 0
Net operating loss carryforwards	$ 1,800,000

Income Taxes (Significant Compo

Income Taxes (Significant Components Of Deferred Tax Liabilities And Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accrued Income Taxes [Abstract]
Net operating loss and AMT credits carryforwards	$ 689,441	$ 781,899
Capital loss carryforwards	40,356	40,356
Equity-based compensation	17,372	14,856
Oil and natural gas properties, gathering assets, and equipment	356,471	0
Debt restructuring	122,900	0
Goodwill	1,308	5,419
Investment in partnerships	76,099	72,988
Other	3,387	2,668
Total non-current deferred tax assets	1,307,334	918,186
Valuation allowance	(1,286,695)	(826,852)
Total non-current deferred tax assets	20,639	91,334
Oil and natural gas properties, gathering assets, and equipment	0	(51,961)
Derivative financial instruments	(20,639)	(39,373)
Total non-current deferred tax liabilities	(20,639)	(91,334)
Net non-current deferred tax assets (liabilities)	$ 0	$ 0

Income Taxes (Reconciliation Of

Income Taxes (Reconciliation Of Income Tax Provision (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accrued Income Taxes [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%	35.00%	35.00%
Federal income taxes (benefit) provision at statutory rate of 35%	$ (417,333)	$ 42,234	$ 7,772
Goodwill	0	0	16,382
Adjustments to the valuation allowance	459,843	(64,757)	(28,865)
Non-deductible compensation	2,399	3,409	1,328
State taxes net of federal benefit	(45,009)	3,464	3,239
State tax rate change	0	15,496	0
Other	100	154	144
Total income tax (benefit)	$ 0	$ 0	$ 0

Income Taxes Income Taxes (Narr

Income Taxes Income Taxes (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Tax Credit Carryforward [Line Items]
Operating Loss Carryforwards	$ 1,800
Cancellation of debt income	538
Deferred Tax Assets, Net of Valuation Allowance, Current		$ 35.9
Alternative minimum tax [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Amount	$ 1.5
Capital Loss Carryforward [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Amount		$ 105.6

Related Party Transactions (Nar

Related Party Transactions (Narrative) (Details) - USD ($)	Sep. 08, 2015	Mar. 31, 2015	Jan. 17, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 19, 2013
Related Party Transaction [Line Items]
Common stock, par value	$ 0.001			$ 0.001	$ 0.001
Class of Warrant or Right, Number of Securities Called by Warrants or Rights							0.25
Payments of Financing Costs				$ 20,946,000	$ 10,426,000	$ 33,553,000
Interest Paid				$ 117,463,000	$ 91,735,000	$ 88,936,000
Fairfax [Member]
Related Party Transaction [Line Items]
beneficial ownership of outstanding common shares				9.00%
Payments of Financing Costs				$ 6,000,000
Interest Paid				6,900,000
Energy Strategic Advisory Services LLC (ESAS) [Member]
Related Party Transaction [Line Items]
Services and Investment Agreement, Term		4 years
Stock Issued During Period, Shares, New Issues	5,882,353
Services and Investment Agreement, Price Per Share	$ 1.70
Services and Investment Agreement, Share Purchase Obligation, Due in 12 Months After Closing				$ 13,500,000
Services and investment Agreement, Shares Purchased				12,464,130
Services and Investment Agreement, Share Purchase Obligation, Total				$ 23,500,000
beneficial ownership of outstanding common shares				6.50%
Services and Investment Agreement, Monthly Fee				$ 300,000
Services and Investment Agreement, Annual Incentive Payment				$ 1,800,000
Class of Warrant or Right, Number of Securities Called by Warrants or Rights				80,000,000
Affiliated Entity - WL Ross [Member]
Related Party Transaction [Line Items]
Stock Issued During Period, Shares, New Issues			19,599,973
Bottom Half of Peer Group [Member] | Energy Strategic Advisory Services LLC (ESAS) [Member]
Related Party Transaction [Line Items]
Services and Investment Agreement, Annual Incentive Payment				$ 0
50th to 74th Percentile of Peer Group [Member] | Energy Strategic Advisory Services LLC (ESAS) [Member]
Related Party Transaction [Line Items]
Services and Investment Agreement, Annual Incentive Payment				1,000,000
75th Percentile or Above of Peer Group [Member] | Energy Strategic Advisory Services LLC (ESAS) [Member]
Related Party Transaction [Line Items]
Services and Investment Agreement, Annual Incentive Payment				$ 2,400,000

Related Party Transactions (Det

Related Party Transactions (Details) - OPCO [Member] - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Advances to OPCO		$ 0	$ 0	$ 28,378
Amounts received from OPCO		30,577	53,002	$ 43,632
Amounts due to EXCO (1)	[1]	1,733	2,799
Amounts due from EXCO (1)	[1]	$ 10,410	$ 0
[1]	Advances to OPCO are recorded in "Inventory and other" on our Condensed Consolidated Balance Sheets. Any amounts we owe to OPCO are netted against the advance until the advances are utilized. If the advances are fully utilized, we record amounts owed in "Accounts payable and accrued liabilities" on our Condensed Consolidated Balance Sheets.

Rights Offering and other equ71

Rights Offering and other equity transactions (Details) - USD ($) $ / shares in Units, $ in Thousands	Jan. 17, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 19, 2013
Class of Stock [Line Items]
Class of Warrant or Right, Number of Securities Called by Warrants or Rights					0.25
Share Price					$ 5
Common stock, shares issued	54,574,734	283,633,996	274,351,756
Proceeds from issuance of common stock	$ 272,900	$ 9,693	$ 271,773	$ 1,712
Preferred Stock, Shares Authorized		10,000,000
Preferred Stock, Shares Issued		0
Preferred Stock, Shares Outstanding		0
Affiliated Entity - WL Ross [Member]
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues	19,599,973
Affiliated Entity - Hamblin Watsa [Member]
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues	6,726,712

Condensed Consolidating Finan72

Condensed Consolidating Financial Statements (Schedule Of Condensed Consolidating Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 12,247	$ 46,305	$ 50,483	$ 45,644
Restricted cash	21,220	23,970
Other current assets	116,334	260,491
Total current assets	149,801	330,766
Equity investments	40,797	55,985
Unproved oil and natural gas properties and development costs not being amortized	115,377	276,025
Proved developed and undeveloped oil and natural gas properties	3,070,430	3,852,073
Accumulated depletion	(2,627,763)	(2,414,461)
Oil and natural gas properties, net	558,044	1,713,637
Other property and equipment, net	27,812	24,644
Investments in and advances to affiliates	0	0
Deferred financing costs, net	8,408	14,617
Derivative financial instruments	6,109	2,138
Goodwill	163,155	163,155
Total assets	954,126	2,304,942
Liabilities and shareholders’ equity
Current liabilities	252,919	329,436
Long-term debt	1,320,279	1,430,516
Other long-term liabilities	43,251	34,986
Payable to parent	0	0
Total shareholders' equity	(662,323)	510,004	147,905	149,393
Total liabilities and shareholders' equity	954,126	2,304,942
Resources [Member]
Current assets:
Cash and cash equivalents	34,296	86,837	81,840	65,791
Restricted cash	2,100	0
Other current assets	51,133	110,145
Total current assets	87,529	196,982
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	330,775	335,838
Accumulated depletion	(330,775)	(330,771)
Oil and natural gas properties, net	0	5,067
Other property and equipment, net	749	1,269
Investments in and advances to affiliates	616,940	1,746,931
Deferred financing costs, net	8,408	14,617
Derivative financial instruments	6,109	2,138
Goodwill	13,293	13,293
Total assets	733,028	1,980,297
Liabilities and shareholders’ equity
Current liabilities	74,472	39,506
Long-term debt	1,320,279	1,430,516
Other long-term liabilities	600	271
Payable to parent	0	0
Total shareholders' equity	(662,323)	510,004
Total liabilities and shareholders' equity	733,028	1,980,297
Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	(22,049)	(40,532)	(35,892)	(20,147)
Restricted cash	19,120	23,970
Other current assets	65,201	150,346
Total current assets	62,272	133,784
Equity investments	0	0
Unproved oil and natural gas properties and development costs not being amortized	115,377	276,025
Proved developed and undeveloped oil and natural gas properties	2,739,655	3,516,235
Accumulated depletion	(2,296,988)	(2,083,690)
Oil and natural gas properties, net	558,044	1,708,570
Other property and equipment, net	27,063	23,375
Investments in and advances to affiliates	0	0
Deferred financing costs, net	0	0
Derivative financial instruments	0	0
Goodwill	149,862	149,862
Total assets	797,241	2,015,591
Liabilities and shareholders’ equity
Current liabilities	178,447	289,930
Long-term debt	0	0
Other long-term liabilities	42,651	34,715
Payable to parent	2,276,594	2,058,683
Total shareholders' equity	(1,700,451)	(367,737)
Total liabilities and shareholders' equity	797,241	2,015,591
Non-Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	0	0	4,535	0
Restricted cash	0	0
Other current assets	0	0
Total current assets	0	0
Equity investments	40,797	55,985
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	0	0
Investments in and advances to affiliates	0	0
Deferred financing costs, net	0	0
Derivative financial instruments	0	0
Goodwill	0	0
Total assets	40,797	55,985
Liabilities and shareholders’ equity
Current liabilities	0	0
Long-term debt	0	0
Other long-term liabilities	0	0
Payable to parent	0	0
Total shareholders' equity	40,797	55,985
Total liabilities and shareholders' equity	40,797	55,985
Eliminations [Member]
Current assets:
Cash and cash equivalents	0	0	$ 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	0	0
Investments in and advances to affiliates	(616,940)	(1,746,931)
Deferred financing costs, net	0	0
Derivative financial instruments	0	0
Goodwill	0	0
Total assets	(616,940)	(1,746,931)
Liabilities and shareholders’ equity
Current liabilities	0	0
Long-term debt	0	0
Other long-term liabilities	0	0
Payable to parent	(2,276,594)	(2,058,683)
Total shareholders' equity	1,659,654	311,752
Total liabilities and shareholders' equity	$ (616,940)	$ (1,746,931)

Condensed Consolidating Finan73

Condensed Consolidating Financial Statements (Schedule Of Condensed Consolidating Statement Of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and natural gas	$ 64,743		$ 83,526		$ 93,742		$ 86,320		$ 127,789	$ 151,042	$ 182,966	$ 198,472	$ 328,331	$ 660,269	$ 634,309
Oil and natural gas production													76,533	94,326	83,248
Gathering and transportation													99,321	101,574	100,645
Depletion, depreciation and amortization													215,426	263,569	245,775
Impairment of oil and natural gas properties	205,300		339,400		394,300		276,300						1,215,370	0	108,546
Accretion of discount on asset retirement obligations													2,277	2,690	2,514
General and administrative													58,818	65,920	91,878
Other operating items													461	5,315	(177,518)
Total costs and expenses													1,668,206	533,394	455,088
Operating income (loss)	(240,817)	[1]	(363,975)	[1]	(421,465)	[1]	(313,618)	[1]	3,341	22,799	43,312	57,423	(1,339,875)	126,875	179,221
Interest expense, net													(106,082)	(94,284)	(102,589)
Gain (loss) on derivative financial instruments													75,869	87,665	(320)
Gain on restructuring and extinguishment of debt	193,300												193,276	0	0
Other income (expense)													122	241	(828)
Equity income (loss)													(15,691)	172	(53,280)
Net earnings (loss) from consolidated subsidiaries													0	0	0
Total other income (expense)													147,494	(6,206)	(157,017)
Income (loss) before income taxes													(1,192,381)	120,669	22,204
Income tax expense													0	0	0
Net income (loss)	$ (65,595)	[2]	$ (354,519)	[2]	$ (454,155)	[2]	$ (318,112)	[2]	$ 81,413	$ 41,569	$ 2,293	$ (4,606)	(1,192,381)	120,669	22,204
Resources [Member]
Oil and natural gas													4	3,649	9,136
Oil and natural gas production													37	394	2,440
Gathering and transportation													0	0	0
Depletion, depreciation and amortization													943	3,174	5,917
Impairment of oil and natural gas properties													9,316	0	0
Accretion of discount on asset retirement obligations													4	16	63
General and administrative													(4,313)	(3,342)	23,125
Other operating items													1,646	(134)	(25,950)
Total costs and expenses													7,633	108	5,595
Operating income (loss)													(7,629)	3,541	3,541
Interest expense, net													(106,082)	(92,049)	(99,815)
Gain (loss) on derivative financial instruments													75,869	87,565	1,439
Gain on restructuring and extinguishment of debt													193,276
Other income (expense)													87	226	(1,068)
Equity income (loss)													0	0	0
Net earnings (loss) from consolidated subsidiaries													(1,347,902)	121,386	118,107
Total other income (expense)													(1,184,752)	117,128	18,663
Income (loss) before income taxes													(1,192,381)	120,669	22,204
Income tax expense													0	0	0
Net income (loss)													(1,192,381)	120,669	22,204
Guarantor Subsidiaries [Member]
Oil and natural gas													328,327	614,889	582,158
Oil and natural gas production													76,496	77,334	63,716
Gathering and transportation													99,321	97,784	97,166
Depletion, depreciation and amortization													214,483	244,761	225,499
Impairment of oil and natural gas properties													1,206,054	0	108,546
Accretion of discount on asset retirement obligations													2,273	2,107	1,881
General and administrative													63,131	66,686	66,558
Other operating items													(1,185)	5,459	(151,549)
Total costs and expenses													1,660,573	494,131	411,817
Operating income (loss)													(1,332,246)	120,758	170,341
Interest expense, net													0	0	0
Gain (loss) on derivative financial instruments													0	0	(177)
Gain on restructuring and extinguishment of debt													0
Other income (expense)													35	0	229
Equity income (loss)													0	0	0
Net earnings (loss) from consolidated subsidiaries													0	0	0
Total other income (expense)													35	0	52
Income (loss) before income taxes													(1,332,211)	120,758	170,393
Income tax expense													0	0	0
Net income (loss)													(1,332,211)	120,758	170,393
Non-Guarantor Subsidiaries [Member]
Oil and natural gas													0	41,731	43,015
Oil and natural gas production													0	16,598	17,092
Gathering and transportation													0	3,790	3,479
Depletion, depreciation and amortization													0	15,634	14,359
Impairment of oil and natural gas properties													0	0	0
Accretion of discount on asset retirement obligations													0	567	570
General and administrative													0	2,576	2,195
Other operating items													0	(10)	(19)
Total costs and expenses													0	39,155	37,676
Operating income (loss)													0	2,576	5,339
Interest expense, net													0	(2,235)	(2,774)
Gain (loss) on derivative financial instruments													0	100	(1,582)
Gain on restructuring and extinguishment of debt													0
Other income (expense)													0	15	11
Equity income (loss)													(15,691)	172	(53,280)
Net earnings (loss) from consolidated subsidiaries													0	0	0
Total other income (expense)													(15,691)	(1,948)	(57,625)
Income (loss) before income taxes													(15,691)	628	(52,286)
Income tax expense													0	0	0
Net income (loss)													(15,691)	628	(52,286)
Eliminations [Member]
Oil and natural gas													0	0	0
Oil and natural gas production													0	0	0
Gathering and transportation													0	0	0
Depletion, depreciation and amortization													0	0	0
Impairment of oil and natural gas properties													0	0	0
Accretion of discount on asset retirement obligations													0	0	0
General and administrative													0	0	0
Other operating items													0	0	0
Total costs and expenses													0	0	0
Operating income (loss)													0	0	0
Interest expense, net													0	0	0
Gain (loss) on derivative financial instruments													0	0	0
Gain on restructuring and extinguishment of debt													0
Other income (expense)													0	0	0
Equity income (loss)													0	0	0
Net earnings (loss) from consolidated subsidiaries													1,347,902	(121,386)	(118,107)
Total other income (expense)													1,347,902	(121,386)	(118,107)
Income (loss) before income taxes													1,347,902	(121,386)	(118,107)
Income tax expense													0	0	0
Net income (loss)													$ 1,347,902	$ (121,386)	$ (118,107)
[1]	Operating loss for the first, second, third and fourth quarter of 2015 includes $276.3 million, $394.3 million, $339.4 million and $205.3 million, respectively, of impairments of oil and natural gas properties. See "Note 2. Summary of significant accounting policies" for further discussion.
[2]	Net loss for the fourth quarter of 2015 includes a $193.3 million net gain on restructuring and extinguishment of debt. See "Note 5. Debt" for further discussion.

Condensed Consolidating Finan74

Condensed Consolidating Financial Statements (Schedule Of Condensed Consolidating Statement Of Cash Flows) (Details) - USD ($) $ in Thousands	Jan. 17, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net cash provided by (used in) operating activities		$ 134,027	$ 362,093	$ 350,634
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions		(325,198)	(402,566)	(1,297,252)
Proceeds from disposition of property and equipment		7,397	187,655	749,628
Restricted cash		4,850	(3,400)	49,515
Distributions received from Compass			0	0
Net changes in advances to joint ventures		10,663	(5,026)	10,645
Equity investments and other		1,455	1,749	234,986
Advances/investments with affiliates		0	0	0
Net cash used in investing activities		(300,833)	(221,588)	(252,478)
Borrowings under credit agreements		165,000	100,000	1,004,523
Repayments under credit agreements		(300,000)	(964,970)	(1,022,785)
Proceeds received from issuance of 2022 Notes		0	500,000	0
Proceeds received from issuance of Fairfax Term Loan		300,000	0	0
Repurchases of 2018 Notes		(12,008)	0	0
Payment on Exchange Term Loan		(8,827)	0	0
Proceeds from issuance of common shares, net	$ 272,900	9,693	271,773	1,712
Payment of common share dividends		(164)	(41,060)	(43,214)
Compass cash distribution			0	0
Deferred financing costs and other		(20,946)	(10,426)	(33,553)
Net cash provided by (used in) financing activities		132,748	(144,683)	(93,317)
Net increase (decrease) in cash		(34,058)	(4,178)	4,839
Cash at beginning of period		46,305	50,483	45,644
Cash at end of period		12,247	46,305	50,483
Resources [Member]
Net cash provided by (used in) operating activities		34,532	(84,067)	(32,678)
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions		(2,601)	(2,531)	(15,767)
Proceeds from disposition of property and equipment		686	99,612	244,500
Restricted cash		0	0	0
Distributions received from Compass			5,856	3,825
Net changes in advances to joint ventures		0	0	0
Equity investments and other		0	0	(1,303)
Advances/investments with affiliates		(217,906)	125,612	(59,575)
Net cash used in investing activities		(219,821)	228,549	171,680
Borrowings under credit agreements		165,000	100,000	967,766
Repayments under credit agreements		(300,000)	(959,874)	(1,015,900)
Proceeds received from issuance of 2022 Notes			500,000
Proceeds received from issuance of Fairfax Term Loan		300,000
Repurchases of 2018 Notes		(12,008)
Payment on Exchange Term Loan		(8,827)
Proceeds from issuance of common shares, net		9,693	271,773	1,712
Payment of common share dividends		(164)	(41,060)	(43,214)
Compass cash distribution			0	0
Deferred financing costs and other		(20,946)	(10,324)	(33,317)
Net cash provided by (used in) financing activities		132,748	(139,485)	(122,953)
Net increase (decrease) in cash		(52,541)	4,997	16,049
Cash at beginning of period		86,837	81,840	65,791
Cash at end of period		34,296	86,837	81,840
Guarantor Subsidiaries [Member]
Net cash provided by (used in) operating activities		99,495	428,029	365,770
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions		(322,597)	(395,974)	(1,242,667)
Proceeds from disposition of property and equipment		6,711	95,594	505,128
Restricted cash		4,850	(3,400)	49,515
Distributions received from Compass			0	0
Net changes in advances to joint ventures		10,663	(5,026)	10,645
Equity investments and other		1,455	1,749	236,289
Advances/investments with affiliates		217,906	(125,612)	59,575
Net cash used in investing activities		(81,012)	(432,669)	(381,515)
Borrowings under credit agreements		0	0	0
Repayments under credit agreements		0	0	0
Proceeds received from issuance of 2022 Notes			0
Proceeds received from issuance of Fairfax Term Loan		0
Repurchases of 2018 Notes		0
Payment on Exchange Term Loan		0
Proceeds from issuance of common shares, net		0	0	0
Payment of common share dividends		0	0	0
Compass cash distribution			0	0
Deferred financing costs and other		0	0	0
Net cash provided by (used in) financing activities		0	0	0
Net increase (decrease) in cash		18,483	(4,640)	(15,745)
Cash at beginning of period		(40,532)	(35,892)	(20,147)
Cash at end of period		(22,049)	(40,532)	(35,892)
Non-Guarantor Subsidiaries [Member]
Net cash provided by (used in) operating activities		0	18,131	17,542
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions		0	(4,061)	(38,818)
Proceeds from disposition of property and equipment		0	(7,551)	0
Restricted cash		0	0	0
Distributions received from Compass			0	0
Net changes in advances to joint ventures		0	0	0
Equity investments and other		0	0	0
Advances/investments with affiliates		0	0	0
Net cash used in investing activities		0	(11,612)	(38,818)
Borrowings under credit agreements		0	0	36,757
Repayments under credit agreements		0	(5,096)	(6,885)
Proceeds received from issuance of 2022 Notes			0
Proceeds received from issuance of Fairfax Term Loan		0
Repurchases of 2018 Notes		0
Payment on Exchange Term Loan		0
Proceeds from issuance of common shares, net		0	0	0
Payment of common share dividends		0	0	0
Compass cash distribution			(5,856)	(3,825)
Deferred financing costs and other		0	(102)	(236)
Net cash provided by (used in) financing activities		0	(11,054)	25,811
Net increase (decrease) in cash		0	(4,535)	4,535
Cash at beginning of period		0	4,535	0
Cash at end of period		0	0	4,535
Eliminations [Member]
Net cash provided by (used in) operating activities		0	0	0
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions		0	0	0
Proceeds from disposition of property and equipment		0	0	0
Restricted cash		0	0	0
Distributions received from Compass			(5,856)	(3,825)
Net changes in advances to joint ventures		0	0	0
Equity investments and other		0	0	0
Advances/investments with affiliates		0	0	0
Net cash used in investing activities		0	(5,856)	(3,825)
Borrowings under credit agreements		0	0	0
Repayments under credit agreements		0	0	0
Proceeds received from issuance of 2022 Notes			0
Proceeds received from issuance of Fairfax Term Loan		0
Repurchases of 2018 Notes		0
Payment on Exchange Term Loan		0
Proceeds from issuance of common shares, net		0	0	0
Payment of common share dividends		0	0	0
Compass cash distribution			5,856	3,825
Deferred financing costs and other		0	0	0
Net cash provided by (used in) financing activities		0	5,856	3,825
Net increase (decrease) in cash		0	0	0
Cash at beginning of period		0	0	0
Cash at end of period		$ 0	$ 0	$ 0

Quarterly Financial Data (una75

Quarterly Financial Data (unaudited) (Schedule Of Quarterly Financial Information) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and natural gas revenues	$ 64,743		$ 83,526		$ 93,742		$ 86,320		$ 127,789	$ 151,042	$ 182,966	$ 198,472	$ 328,331	$ 660,269	$ 634,309
Operating income (loss)	(240,817)	[1]	(363,975)	[1]	(421,465)	[1]	(313,618)	[1]	3,341	22,799	43,312	57,423	(1,339,875)	126,875	179,221
Net income (loss)	$ (65,595)	[2]	$ (354,519)	[2]	$ (454,155)	[2]	$ (318,112)	[2]	$ 81,413	$ 41,569	$ 2,293	$ (4,606)	$ (1,192,381)	$ 120,669	$ 22,204
Net income (loss) per basic common share	$ (0.24)		$ (1.30)		$ (1.67)		$ (1.17)		$ 0.30	$ 0.15	$ 0.01	$ (0.02)	$ (4.36)	$ 0.45	$ 0.10
Weighted average shares	277,995		273,348		271,549		271,522		271,053	270,631	270,492	260,716	273,621	268,258	215,011
Net income (loss) per diluted common share	$ (0.24)		$ (1.30)		$ (1.67)		$ (1.17)		$ 0.30	$ 0.15	$ 0.01	$ (0.02)	$ (4.36)	$ 0.45	$ 0.10
Weighted average shares	277,995		273,348		271,549		271,522		271,053	272,066	271,226	260,716	273,621	268,376	230,912
Impairment of oil and natural gas properties	$ 205,300		$ 339,400		$ 394,300		$ 276,300						$ 1,215,370	$ 0	$ 108,546
Net gain on restructuring of debt	$ 193,300												$ 193,276	$ 0	$ 0
[1]	Operating loss for the first, second, third and fourth quarter of 2015 includes $276.3 million, $394.3 million, $339.4 million and $205.3 million, respectively, of impairments of oil and natural gas properties. See "Note 2. Summary of significant accounting policies" for further discussion.
[2]	Net loss for the fourth quarter of 2015 includes a $193.3 million net gain on restructuring and extinguishment of debt. See "Note 5. Debt" for further discussion.

Supplemental Information Rela76

Supplemental Information Relating To Oil And Natural Gas Producing Activities (unaudited) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015$ / bbl$ / MMBTU	Dec. 31, 2014$ / bbl$ / MMBTU	Dec. 31, 2013$ / bbl$ / MMBTU
Extractive Industries [Abstract]
Valuation of proved reserves on discounted rate	10.00%
Reference prices per bbl of oil | $ / bbl	50.28	94.99	96.78
Reference prices per mmbtu of natural gas | $ / MMBTU	2.59	4.35	3.67

Supplemental Information Rela77

Supplemental Information Relating To Oil And Natural Gas Producing Activities (unaudited) (Costs Incurred In Oil And Natural Gas Property Acquisition, Exploration And Development Activities) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / Boe$ / Mcfe		Dec. 31, 2014USD ($)$ / Boe$ / Mcfe		Dec. 31, 2013USD ($)$ / Boe$ / Mcfe
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved property acquisition costs	$ 7,608		$ 10,562		$ 754,370
Unproved property acquisition costs	0		0		232,020
Total property acquisition costs	7,608		10,562		986,390	[1]
Development	215,239		354,199		231,447
Exploration costs	13,306	[2]	5,906	[3]	38,579	[4]
Lease acquisitions and other	13,017		9,681		14,835
Capitalized asset retirement costs	$ 881		$ 576		$ 514
Depletion per Boe | $ / Boe	10.32		11.42		8.82
Depletion per Mcfe | $ / Mcfe	1.72		1.90		1.47
Bossier Shale [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs			$ 5,900
Eagle Ford [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs					$ 29,200
Marcellus Shale [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs					$ 9,400
[1]	Acquisition costs in 2013 include the acquisition of properties in the Haynesville and Eagle Ford shales and our proportionate share of Compass's acquisition of shallow Cotton Valley assets.
[2]	Exploration costs in 2015 primarily relate to the wells drilled in the Buda formation in South Texas.
[3]	Exploration costs in 2014 include $5.9 million in the Bossier shale in North Louisiana.
[4]	Exploration costs in 2013 include $29.2 million in the Eagle Ford shale and $9.4 million in the Marcellus shale.

Supplemental Information Rela78

Supplemental Information Relating To Oil And Natural Gas Producing Activities (unaudited) (Reserve Quantities) (Details) bbl in Thousands, Mcf in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2015USD ($)McfebblMcf		Dec. 31, 2014USD ($)McfebblMcf		Dec. 31, 2013USD ($)McfebblMcf
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure of discounted future net cash flows | $		$ 402,133		$ 1,542,587		$ 1,252,273
Oil [Member]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Beginning balance | bbl		17,687		15,378		5,570
Purchase of reserves in place | bbl		459	[1]	0	[2]	16,022	[3]
Discoveries and extensions | bbl		7,602	[4]	4,164	[5]	5,960	[6]
Changes in price | bbl		(2,821)		45		457
Revisions to Proved Developed and Undeveloped Reserves | bbl		(145)	[7]	1,737	[8]	(3,219)	[9]
Sales of reserves in place | bbl		(1)		(1,401)	[10]	(8,224)	[11]
Production | bbl		(2,342)		(2,236)		(1,188)
Ending balance | bbl		20,439		17,687		15,378
Proved developed | bbl		12,056		14,429		11,274
Proved undeveloped | bbl		8,383		3,258		4,104
Natural Gas [Member]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Beginning balance | Mcf	[12]	1,157,674		1,031,977		975,966
Purchase of reserves in place | Mcf	[12]	122	[1]	7,316	[2]	304,139	[3]
Discoveries and extensions | Mcf	[12]	152,473	[4]	70,544	[5]	49,912	[6]
Changes in price | Mcf	[12]	(598,865)		168,064		276,730
Revisions to Proved Developed and Undeveloped Reserves | Mcf	[12]	184,641	[7]	120,802	[8]	(111,141)	[9]
Sales of reserves in place | Mcf	[12]	(1,445)		(118,705)	[10]	(308,850)	[11]
Production | Mcf	[12]	(109,926)		(122,324)		(154,779)
Ending balance | Mcf	[12]	784,674		1,157,674		1,031,977
Proved developed | Mcf		364,932		504,636		669,644
Proved undeveloped | Mcf		419,742		653,038		362,333
Mcfe [Member]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Net (Mcfe)	[13]	1,263,796,000		1,124,245,000		1,009,386,000
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place (Mcfe)	[13]	2,876,000	[1]	7,316,000	[2]	400,271,000	[3]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions (Mcfe)	[13]	198,085,000	[4]	95,528,000	[5]	85,672,000	[6]
Revisions To Proved Developed And Undeveloped Reserves Due To Changes In Price (Mcfe)	[13]	(615,791,000)		168,334,000		279,472,000
Revisions to Proved Developed and Undeveloped Reserves due to other Factors (Mcfe)	[13]	183,771,000	[7]	131,224,000	[8]	(130,455,000)	[9]
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place (Mcfe)	[13]	(1,451,000)		(127,111,000)	[10]	(358,194,000)	[11]
Proved Developed and Undeveloped Reserves, Production (Mcfe)	[13]	(123,978,000)		(135,740,000)		(161,907,000)
Proved Developed and Undeveloped Reserves, Net (Mcfe)	[13]	907,308,000		1,263,796,000		1,124,245,000
Proved developed		437,268,000		591,210,000		737,291,000
Proved Undeveloped Reserves (Energy)		470,040,000		672,586,000		386,954,000
Holly area [Member]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions (Mcfe)		24,700,000
Revisions to Proved Developed and Undeveloped Reserves due to other Factors (Mcfe)		152,200,000		5,800,000
Appalachia [Member]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Revisions to Proved Developed and Undeveloped Reserves due to other Factors (Mcfe)				45,900,000
Marcellus Shale [Member]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions (Mcfe)						33,600,000
Permian [Member]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place (Mcfe)						1,500,000
Eagle Ford [Member]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place (Mcfe)						115,700,000
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions (Mcfe)		47,500,000		26,100,000		36,500,000
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place (Mcfe)						(30,600,000)
Haynesville Shale [Member]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place (Mcfe)						260,000,000
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions (Mcfe)		84,900,000		48,700,000		10,200,000
Bossier Shale [Member]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions (Mcfe)		41,000,000		19,700,000
Shelby Area [Member]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Revisions to Proved Developed and Undeveloped Reserves due to other Factors (Mcfe)		36,700,000		67,100,000
Compass [Member]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place (Mcfe)						24,600,000
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions (Mcfe)						3,900,000
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place (Mcfe)						(327,600,000)
[1]	Purchases of reserves in place include the acquisition of certain proved developed producing properties in the Eagle Ford shale in connection with the Participation Agreement
[2]	Purchases of reserves in place in 2014 consist primarily of our acquisition of certain proved developed producing properties in the Shelby area of East Texas.
[3]	Purchases of reserves in place include 115.7 Bcfe in the Eagle Ford shale, 260.0 Bcfe in the Haynesville shale, and 24.6 Bcfe for our proportionate share of Compass's acquisition of shallow Cotton Valley assets in East Texas/North Louisiana.
[4]	New discoveries and extensions in 2015 include 84.9 Bcfe and 41.0 Bcfe in the Haynesville shale and Bossier shale, respectively, related to our development of properties within the Shelby area of East Texas. Additionally, extensions and discoveries in 2015 included 24.7 Bcfe in the in the Haynesville shale related to the development of the Holly area in North Louisiana and 47.5 Bcfe in the Eagle Ford shale.
[5]	New discoveries and extensions in 2014 included 48.7 Bcfe in the Haynesville shale, 26.1 Bcfe in the Eagle Ford Shale and 19.7 Bcfe in the Bossier shale. The discoveries and extensions within the Haynesville and Bossier shales primarily related to our development of properties within the Shelby area of East Texas.
[6]	New discoveries and extensions in 2013 include 36.5 Bcfe in the Eagle Ford shale, 33.6 Bcfe in the Marcellus shale, 10.2 Bcfe in the Haynesville shale, 3.9 Bcfe for conventional properties held by Compass in the Permian Basin, and 1.5 Bcfe for shale properties in the Permian Basin.
[7]	Total revisions due to Other factors include upward revisions of approximately 152.2 Bcfe in the North Louisiana Holly area and are primarily due to modifications in the well design to incorporate more proppant and longer laterals. The upward revisions also included 36.7 Bcfe from our East Texas region primarily due to strong results in both the Haynesville and Bossier shales based on our enhanced completion methods. The upward revisions also reflect a reduction in capital costs and operating expenses.
[8]	Total revisions due to Other factors include upward revisions of approximately 67.1 Bcfe in the Shelby area, approximately 45.9 Bcfe in the Appalachia region, and approximately 5.8 Bcfe in the Holly area. The upward revisions were primarily due to improved well performance resulting from enhanced well designs and completion techniques.
[9]	Total revisions due to Other factors were downward revisions primarily in the Haynesville shale as a result of operational matters including scaling, liquid loading due to high-line pressure and the impact of drainage on new wells drilled directly offset to the unit wells.
[10]	Sales of reserves in place in 2014 consist primarily of the sale of our entire interest in Compass.
[11]	Sales of reserves in place in 2013 include 327.6 Bcfe as a result of our contribution of properties to Compass and 30.6 Bcfe from the sale of undeveloped properties in the Eagle Ford in connection with the Participation Agreement.
[12]	Beginning in 2015, we began reporting our NGLs as a component of natural gas as NGLs are not considered to be significant. Primarily all of our prior period NGLs were associated with properties owned by Compass, which EXCO divested in 2014. Prior period information has been conformed to be consistent with current period information.
[13]	The above reserves do not include our equity interest in OPCO, which was not significant in any period presented.

Supplemental Information Rela79

Supplemental Information Relating To Oil And Natural Gas Producing Activities (unaudited) (Standardized Measure Of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Future cash inflows	$ 2,684,362	$ 6,097,207	$ 5,176,030
Future production costs	1,280,795	2,094,796	2,207,230
Future development costs	641,768	1,124,873	904,116
Future income taxes	0	0	0
Future net cash flows	761,799	2,877,538	2,064,684
Discount of future net cash flows at 10% per annum	359,666	1,334,951	812,411
Standardized measure of discounted future net cash flows	$ 402,133	$ 1,542,587	$ 1,252,273

Supplemental Information Rela80

Supplemental Information Relating To Oil And Natural Gas Producing Activities (unaudited) (Principal Sources Of Change In The Standardized Measure) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Sales and transfers of oil and natural gas produced	$ (152,937)	$ (464,369)	$ (450,415)
Net changes in prices and production costs	(1,438,490)	279,944	582,725
Extensions and discoveries, net of future development and production costs	99,818	196,796	197,223
Development costs during the period	109,895	189,155	55,196
Changes in estimated future development costs	407,780	(254,737)	(251,484)
Revisions of previous quantity estimates	(232,325)	412,296	98,283
Sales of reserves in place	(1,632)	(148,226)	(315,758)
Purchase of reserves in place	6,892	13,507	604,366
Accretion of discount before income taxes	126,533	125,227	69,615
Changes in timing and other	(65,988)	(59,279)	(33,625)
Net change in income taxes	0	0	0
Net change	$ (1,140,454)	$ 290,314	$ 556,126

Supplemental Information Rela81

Supplemental Information Relating To Oil And Natural Gas Producing Activities (unaudited) (Costs Not Subject To Amortization) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	$ 75,019
Exploration and development	12,100
Capitalized interest	28,258
Total	115,377
2015 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	11,121
Exploration and development	12,100
Capitalized interest	8,464
Total	31,685
2014 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	7,862
Exploration and development	0
Capitalized interest	8,604
Total	16,466
2013 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	12,403
Exploration and development	0
Capitalized interest	5,384
Total	17,787
2012 and prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	43,633
Exploration and development	0
Capitalized interest	5,806
Total	$ 49,439