Exco Resources (EXCO) 10-K 25 Feb 15 2014 FY Annual report Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Feb. 19, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Entity Registrant Name	EXCO RESOURCES INC
Entity Central Index Key	316300
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		273,763,414
Entity Current Reporting Status	Yes
Entity Public Float			$897,416
Entity Voluntary Filers	No
Entity Well-known Seasonal Issuer	No

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$46,305	$50,483
Restricted cash	23,970	20,570
Accounts receivable, net:
Oil and natural gas	81,720	128,352
Joint interest	65,398	70,759
Other	8,945	18,022
Derivative financial instruments	97,278	8,226
Other	7,150	9,442
Total current assets	330,766	305,854
Equity investments	55,985	57,562
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	276,025	425,307
Proved developed and undeveloped oil and natural gas properties	3,852,073	3,554,210
Accumulated depletion	-2,414,461	-2,183,464
Oil and natural gas properties, net	1,713,637	1,796,053
Gathering assets	1,488	33,473
Accumulated depreciation and amortization	-168	-10,338
Gathering assets, net	1,320	23,135
Office, field and other assets, net	23,324	27,233
Deferred financing costs, net	30,636	28,807
Derivative financial instruments	2,138	6,829
Deferred income taxes	35,935	0
Goodwill	163,155	163,155
Total assets	2,356,896	2,408,628
Current liabilities:
Accounts payable and accrued liabilities	110,211	109,217
Revenues and royalties payable	152,651	154,862
Drilling advances	37,648	22,971
Accrued interest payable	26,265	18,144
Current portion of asset retirement obligations	1,769	191
Income taxes payable	0	0
Deferred income taxes	35,935	0
Derivative financial instruments	892	11,919
Current maturities of long-term debt	0	31,866
Total current liabilities	365,371	349,170
Long-term debt	1,446,535	1,858,912
Derivative financial instruments	0	9,671
Asset retirement obligations and other long-term liabilities	34,986	42,970
Commitments and contingencies	0	0
Shareholders’ equity:
Common shares, $0.001 par value; 350,000,000 authorized shares; 274,351,756 shares issued and 273,773,714 shares outstanding at December 31, 2014; 218,783,540 shares issued and 218,244,319 shares outstanding at December 31, 2013	270	215
Subscription rights, $0.001 par value, none issued and outstanding at December 31, 2014; 54,574,734 issued and outstanding at December 31, 2013	0	55
Additional paid-in capital	3,502,209	3,219,748
Accumulated deficit	-2,984,860	-3,064,634
Treasury shares, at cost; 578,042 at December 31, 2014 and 539,221 at December 31, 2013	-7,615	-7,479
Total shareholders' equity	510,004	147,905
Total liabilities and shareholders' equity	$2,356,896	$2,408,628

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Common stock, par value	$0.00	$0.00
Common stock, authorized shares	350,000,000	350,000,000
Common stock, shares issued	274,351,756	218,783,540
Common stock, shares outstanding	273,773,714	218,244,319
Treasury stock, shares	578,042	539,221
Subscription rights, par value		$0.00
Subscription rights, issued	0	54,574,734
Subscription rights, outstanding	0	54,574,734

Consolidated_Statements_Of_Ope

Consolidated Statements Of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Oil	$196,316	$111,440	$62,119
Natural gas	457,946	514,309	462,422
Natural gas liquids	6,007	8,560	22,068
Total revenues	660,269	634,309	546,609
Costs and expenses:
Oil and natural gas operating costs	64,467	61,277	77,127
Production and ad valorem taxes	29,859	21,971	27,483
Gathering and transportation	101,574	100,645	102,875
Depletion, depreciation and amortization	263,569	245,775	303,156
Impairment of oil and natural gas properties	0	108,546	1,346,749
Accretion of discount on asset retirement obligations	2,690	2,514	3,887
General and administrative	65,920	91,878	83,818
Gain (loss) on divestitures and other operating items	5,315	-177,518	17,029
Total costs and expenses	533,394	455,088	1,962,124
Operating income (loss)	126,875	179,221	-1,415,515
Other income (expense):
Interest expense, net	-94,284	-102,589	-73,492
Gain (loss) on derivative financial instruments	87,665	-320	66,133
Other income (expense)	241	-828	969
Equity income (loss)	172	-53,280	28,620
Total other income (expense)	-6,206	-157,017	22,230
Income (loss) before income taxes	120,669	22,204	-1,393,285
Income tax expense	0	0	0
Net income (loss)	$120,669	$22,204	($1,393,285)
Basic:
Net income (loss) (in dollars per share)	$0.45	$0.10	($6.50)
Weighted average common shares outstanding	268,258	215,011	214,321
Diluted:
Net income (loss) (in dollars per share)	$0.45	$0.10	($6.50)
Weighted average common shares and common share equivalents outstanding	268,376	230,912	214,321

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Activities:
Net income (loss)	$120,669	$22,204	($1,393,285)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	263,569	245,775	303,156
Share-based compensation expense	4,962	10,748	8,926
Accretion of discount on asset retirement obligations	2,690	2,514	3,887
Impairment of oil and natural gas properties	0	108,546	1,346,749
(Income) loss from equity investments	-172	53,280	-28,620
(Gain) loss on derivative financial instruments	-87,665	320	-66,133
Cash settlements (payments) of derivative financial instruments	-18,991	42,119	202,078
Amortization of deferred financing costs and discount on debt issuance	12,055	29,624	9,788
(Gain) loss on divestitures and other non-operating items	-17	-185,163	1,303
Effect of changes in:
Accounts receivable	52,007	-46,176	112,919
Other current assets	-2,609	9,627	7,090
Accounts payable and other current liabilities	15,595	57,216	6,928
Net cash provided by operating activities	362,093	350,634	514,786
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment	-391,776	-320,538	-534,175
Property acquisitions	-10,790	-976,714	-2,748
Proceeds from disposition of property and equipment	187,655	749,628	38,045
Restricted cash	-3,400	49,515	85,840
Net changes in advances to joint ventures	-5,026	10,645	851
Equity method investments	1,749	236,289	-14,907
Other	0	-1,303	0
Net cash used in investing activities	-221,588	-252,478	-427,094
Financing Activities:
Borrowings under credit agreements	100,000	1,004,523	53,000
Repayments under credit agreements	-964,970	-1,022,785	-93,000
Proceeds received from issuance of 2022 Notes	500,000	0	0
Proceeds from issuance of common shares, net	271,773	1,712	1,968
Payment of common share dividends	-41,060	-43,214	-34,358
Deferred financing costs and other	-10,290	-33,553	-1,655
Payments of common shares repurchased	-136	0	0
Net cash used in financing activities	-144,683	-93,317	-74,045
Net increase (decrease) in cash	-4,178	4,839	13,647
Cash at beginning of period	50,483	45,644	31,997
Cash at end of period	46,305	50,483	45,644
Supplemental Cash Flow Information:
Cash interest payments	91,735	88,936	86,298
Income tax payments	0	0	0
Supplemental non-cash investing and financing activities:
Capitalized share-based compensation	5,498	7,288	7,513
Capitalized interest	20,060	18,729	23,809
Issuance of common stock for director services	235	93	597
Debt eliminated upon sale of Compass and assumed upon formation of Compass, net for the years ended December 31, 2014 and 2013, respectively	-83,246	58,613	0
Issuance of subscription rights (non-cash)	$0	$55	$0

Consolidated_Statements_Of_Cha

Consolidated Statements Of Changes In Shareholders' Equity (USD $)	Total	Common Stock	Subscription Rights	Treasury Stock	Additional paid-in capital	Accumulated deficit
In Thousands, except Share data, unless otherwise specified
Beginning Balance at Dec. 31, 2011	$1,558,332	$215	$0	($7,479)	$3,181,063	($1,615,467)
Beginning Balance (in shares) at Dec. 31, 2011		217,245,000		539,000
Beginning Balance, Subscription Rights (in shares) at Dec. 31, 2011			0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common shares (in shares)		266,000
Issuance of common shares	2,565	0			2,565
Share-based compensation	16,439				16,439
Restricted shares issued, net of cancellations (in shares)		615,000
Restricted shares issued, net of cancellations	0	0
Common share dividends	-34,658					-34,658
Net income (loss)	-1,393,285					-1,393,285
Ending Balance at Dec. 31, 2012	149,393	215	0	-7,479	3,200,067	-3,043,410
Ending Balance (in shares) at Dec. 31, 2012		218,126,000		539,000
Beginning Balance, Subscription Rights (in shares) at Dec. 31, 2012			0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common shares (in shares)		228,000
Issuance of common shares	1,805	0			1,805
Share-based compensation	17,931				17,931
Restricted shares issued, net of cancellations (in shares)		429,000
Restricted shares issued, net of cancellations	0	0
Common share dividends	-43,428					-43,428
Issuance of subscription rights (in shares)			54,575,000
Issuance of subscription rights	0		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 (in shares) at Dec. 31, 2013		218,783,000		539,000
Ending Balance, Subscription Rights (in shares) at Dec. 31, 2013	54,574,734		54,575,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common shares (in shares)		54,582,000	-54,575,000
Issuance of common shares	272,008	55	-55		272,008
Share-based compensation	10,453				10,453
Restricted shares issued, net of cancellations (in shares)		987,000
Restricted shares issued, net of cancellations	0	0
Common share dividends	-40,895					-40,895
Treasury share repurchases (in shares)				-39,000
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 (in shares) at Dec. 31, 2014		274,352,000		578,000
Ending Balance, Subscription Rights (in shares) at Dec. 31, 2014	0		0

Organization_And_Basis_Of_Pres

Organization And Basis Of Presentation	12 Months Ended
	Dec. 31, 2014
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/North Louisiana
	The East Texas/North Louisiana region is 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 and Bossier shale assets in East Texas and North Louisiana. BG Group’s right to participate in our acquisition of oil and natural gas properties within an area of mutual interest in the East Texas/North Louisiana region expired in August 2014. We serve as the operator for most of our properties in the East Texas/North Louisiana region.
	•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") to develop 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, 2014 and 2013, Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2014, 2013 and 2012 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_Account

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013 and the Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Changes in Shareholders' Equity for the years ended December 31, 2014, 2013 and 2012. 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, share-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/North Louisiana. Funds held in this escrow account are restricted and can be used primarily for drilling and operations in East Texas/North Louisiana.
	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, 2014 and 2013. 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, 2014, 2013 and 2012, sales to BG Energy Merchants LLC accounted for approximately 34%, 48% and 36%, respectively, of total consolidated revenues. BG Energy Merchants LLC is a subsidiary of BG Group. For the years ended December 31, 2014 and 2013, Chesapeake Energy Marketing Inc. accounted for approximately 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 $276.0 million and $425.3 million as of December 31, 2014 and 2013, 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. 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 this evaluation, we did not record an impairment of undeveloped properties during 2014 and recorded impairments of $1.0 million and $60.8 million of undeveloped properties during 2013 and 2012, respectively. These impairments were transferred to the depletable portion of the full cost pool during each year. The impairments were recorded to reflect the estimated market price which included certain properties that were no longer part of our drilling plans.
	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 is computed using the simple average spot price for the trailing 12 month period using the first day of each month. For the 12 months ended December 31, 2014, the trailing 12 month reference prices were $4.35 per Mmbtu for natural gas at Henry Hub ("HH"), and $94.99 per Bbl of oil for West Texas Intermediate ("WTI") at Cushing, Oklahoma. Each of the reference prices for oil and natural gas are further adjusted for quality factors and regional differentials to derive estimated future net revenues. The price used for NGLs was $33.03 per Bbl and was based on the trailing 12 month average of realized prices. 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 ceiling test limitation exceeded the book value of the full cost pool as of December 31, 2014.
	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.
	For the year ended December 31, 2014, we did not recognize an impairment to our proved oil and natural gas properties and for the years ended December 31, 2013 and 2012 we recognized impairments $108.5 million and $1.3 billion, respectively, 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. The impairment of our oil and natural gas properties during 2012 was due to the significant decline in natural gas prices.
	As a result of recent decline in oil and natural gas prices, we expect to incur additional impairments to our oil and natural gas properties in 2015 if prices do not increase. Based on the commodity prices to date during 2015, we expect the reference prices to be utilized in the ceiling test calculation beginning in the first quarter of 2015 to be significantly lower than the price used at December 31, 2014.
	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.
	Office, field and other equipment
	Office, field and other equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives ranging from 3 to 15 years.
	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. Losses, if any, resulting from impairment tests will be reflected in operating income 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 also consider our market capitalization in our evaluation of the fair value of our business. As a result of testing, the fair value of our business exceeded the carrying value of net assets by approximately 18% at December 31, 2014 and we did not record an impairment charge for the periods ending December 31, 2014, 2013 and 2012.
	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)		2014			2013			2012
	Asset retirement obligations at beginning of period		$	42,954		$	61,864		$	58,088
	Activity during the period:
	Liabilities incurred during the period		576			514			971
	Revisions in estimated assumptions		—			1,268			—
	Liabilities settled during the period		(33		)	(187		)	(338		)
	Adjustment to liability due to acquisitions		107			5,566			—
	Adjustment to liability due to divestitures (1)		(9,539		)	(28,585		)	(744		)
	Accretion of discount		2,690			2,514			3,887
	Asset retirement obligations at end of period		36,755			42,954			61,864
	Less current portion		1,769			191			1,200
	Long-term portion		$	34,986		$	42,763		$	60,664
	-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 have no 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, 2014, 2013 and 2012 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. Due to these two distinct selling arrangements, 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 $101.6 million, $100.6 million and $102.9 million for the years ended December 31, 2014, 2013 and 2012, 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, 2014, 2013 and 2012, we capitalized $15.8 million, $18.2 million and $22.5 million, respectively. The capitalized amounts include $5.5 million, $7.3 million and $7.5 million of share-based compensation for the years ended December 31, 2014, 2013 and 2012, respectively.
	Overhead reimbursement fees
	We have classified fees from overhead charges billed to working interest owners of $13.5 million, $10.5 million and $20.5 million for the years ended December 31, 2014, 2013 and 2012, 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 $6.4 million, $5.8 million and $10.3 million for the years ended December 31, 2014, 2013 and 2012, 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 certain properties in the East Texas/North Louisiana JV and the Appalachia JV. 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 will provide certain transition services to Compass for up to nine months following the closing date. For the years ended December 31, 2014, 2013 and 2012, general and administrative expenses were reduced by $24.7 million, $26.8 million and $25.2 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 and restricted share awards. 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 and restricted share awards, 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".
Share-based compensation
We account for our share-based compensation in accordance with FASB ASC Topic 718, Compensation-Stock Compensation ("ASC 718"). 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
In April 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity ("ASU 2014-08"). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity's operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. ASU 2014-08 also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant component of an entity that does not qualify for discontinued operations reporting. ASU 2014-08 retained the scope exception for oil and natural gas properties accounted for under the full-cost method and therefore we do not believe the update will have a significant impact on our consolidated financial condition and results of operations. ASU 2014-08 is effective prospectively to all periods beginning after December 15, 2014. We will apply the guidance prospectively to disposal activity, when applicable, occurring after the effective date of ASU 2014-08.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) ("ASU 2014-09"). The FASB and the International Accounting Standards Board ("IASB") jointly issued this comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under GAAP. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under currently applicable guidance, including identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016 and permits the use of either the retrospective or cumulative effect transition method. We are currently assessing the potential impact of ASU 2014-09 on our consolidated financial condition and results of operations.
In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern ("ASU 2014-15"). ASU 2014-15 provides guidance about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and sets rules for how this information should be disclosed in the financial statements. ASU 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods thereafter. Early adoption is permitted. As discussed in "Note 6. Debt", our ability to maintain compliance with certain debt covenants might be negatively impacted when oil and/or natural gas prices and production declines over an extended period of time. If such event occurs in future periods that could affect our ability to continue as going concern, we will provide appropriate disclosures as required by ASU 2014-15.

Divestitures_Acquisitions_And_

Divestitures, Acquisitions And Other Significant Events	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Acquisition, Divestitures and Other Significant Events	Acquisitions, divestitures and other significant events
	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.
	At the closing, EXCO and HGI terminated the existing operating and administrative services agreements and entered into a customary transition services agreement pursuant to which EXCO will provide certain transition services to Compass for up to nine months following the closing date. In addition, following the closing, EXCO will no longer be 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 East Texas/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. The acquisition added approximately 55 identified drilling locations in the Haynesville shale formation to our drilling inventory. 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.
	Pro forma results of operations - The following table reflects the unaudited pro forma results of operations as though the acquisition of the Haynesville and Eagle Ford assets had occurred on January 1, 2012:
			Year Ended December 31,
	(in thousands, except for per share data)		2013			2012
	Oil and natural gas revenues		$	784,628		$	715,286
	Net income (loss) (1)		$	38,663		$	(1,398,169	)
	Basic earnings (loss) per share		$	0.18		$	(6.52	)
	Diluted earnings (loss) per share		$	0.17		$	(6.52	)
	-1	Net loss for the year ended December 31, 2012 was primarily due to the impairment of our oil and natural gas properties due to the significant decline in natural gas prices.
	KKR Participation Agreement
	In connection with closing the acquisition of the Eagle Ford assets, we entered into a participation agreement with KKR ("Participation Agreement") 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. After giving effect to the KKR payment, the EXCO Resources Credit Agreement borrowing base and outstanding borrowings were reduced by $130.9 million.
	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. These acquisitions are expected to increase the borrowing base under the revolving commitment of the EXCO Resources Credit Agreement and are expected to be funded with borrowings under the EXCO Resources Credit Agreement, cash flows from operations, or other financing arrangements. 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.
	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.
	2012 acquisitions and divestitures
	During 2012, we made acreage purchases in our Appalachia and Permian regions and sold a portion of our West Virginia acreage for net proceeds of $14.3 million.

Derivative_Financial_Instrumen

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2014
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 Condensed Consolidated Balance Sheets and their financial impact on our Condensed Consolidated Statements of Operations.
	Fair Value of Derivative Financial Instruments
	(in thousands)	December 31, 2014				December 31, 2013
	Derivative financial instruments - Current assets	$	97,278			$	8,226
	Derivative financial instruments - Long-term assets	2,138				6,829
	Derivative financial instruments - Current liabilities	(892		)		(11,919		)
	Derivative financial instruments - Long-term liabilities	—				(9,671		)
	Net derivative financial instruments	$	98,524			$	(6,535	)
	The Effect of Derivative Financial Instruments
		Year Ended December 31,
	(in thousands)	2014				2013				2012
	Gain (loss) on derivative financial instruments	$	87,665			$	(320	)		$	66,133
	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 Condensed Consolidated Balance Sheets fair value amounts.
	Our oil and natural gas derivative instruments are comprised of the following instruments:
	Swaps: These contracts allow us to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity.
	Basis swaps: These contracts allow us to receive a fixed price differential between market indices for oil prices based on the delivery point. Our oil basis swaps typically have a positive differential to NYMEX WTI oil prices.
	Call options: These contracts give 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 exceeds the fixed price of the call option, we pay the counterparty the excess. If the market price settles below the fixed price of the call option, no payment is 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.
	Three-way collars: A three-way collar is a combination of options including a sold call, a purchased put and a sold put. These contracts allow us to participate in the upside of commodity prices to the ceiling of the call option and provide us with partial downside protection through the combination of the put options. If the market price is below the strike price of the purchased put at the time of settlement then the counterparty pays us the excess, unless the market price falls below the strike price of the sold put at which point the counterparty pays us the difference between the strike prices of the purchased put and sold put. If the market price is above the strike price of the sold call at the time of settlement, we pay the counterparty the excess. These transactions were conducted contemporaneously with a single counterparty 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, 2014:
	(in thousands, except prices)	Volume Mmbtu/Bbl			Weighted average strike price per Mmbtu/Bbl				Fair value at December 31, 2014
	Natural gas:
	Swaps:
	2015	42,888			$	4.2			49,926
	Call options:
	2015	20,075			4.29				(784		)
	Three-way collars:
	2015	27,375							10,205
	Sold call				4.47
	Purchased put				3.83
	Sold put				3.33
	2016	10,980							2,138
	Sold call				4.8
	Purchased put				3.9
	Sold put				3.4
	Total natural gas								$	61,485
	Oil:
	Swaps:
	2015	1,095			$	91.09			36,797
	Basis swaps:
	2015	91			6.1				350
	Call options:
	2015	365			100				(108		)
	Total oil								$	37,039
	Total oil and natural gas derivative financial instruments								$	98,524
	At December 31, 2013, we had outstanding swap and call option contracts covering 112,348 Mmmbtu and 40,150 Mmmbtu, respectively, of natural gas and we had outstanding swap, basis swap and call option contracts covering 2,192 Mbbls, 274 Mbbls and 730 Mbbls, respectively, of oil.
	At December 31, 2014, the average forward NYMEX WTI oil price per Bbl for the calendar year 2015 was $56.26, the average forward NYMEX Louisiana Light Sweet ("LLS") oil price per barrel for the calendar years 2015 was $58.51 and the average forward NYMEX Henry Hub natural gas prices per Mmbtu for the calendar years 2015 and 2016 were $3.01 and $3.46, respectively.
	Our derivative financial instruments covered approximately 69% and 57% of production volumes for the years ended December 31, 2014 and 2013.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013 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, 2014 and 2013.
		December 31, 2014
	(in thousands)	Level 1		Level 2			Level 3		Total
	Oil and natural gas derivative financial instruments	$	—	$	98,524		$	—	$	98,524
		December 31, 2013
	(in thousands)	Level 1		Level 2			Level 3		Total
	Oil and natural gas derivative financial instruments	$	—	$	(6,535	)	$	—	$	(6,535	)
	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 Condensed 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 are 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 are 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 7.5% senior unsecured notes due September 15, 2018 ("2018 Notes"), our 8.5% senior unsecured notes due April 15, 2022 ("2022 Notes") and the term loan under the EXCO Resources Credit Agreement ("Term Loan"), at December 31, 2014 and December 31, 2013 are presented below. The estimated fair values of the 2018 Notes, 2022 Notes and Term Loan have been calculated based on market quotes.
		December 31, 2014
	(in thousands)	Level 1		Level 2			Level 3		Total
	2018 Notes	$	558,750	$	—		$	—	$	558,750
	2022 Notes	373,500		—			—		373,500
		December 31, 2013
	(in thousands)	Level 1		Level 2			Level 3		Total
	2018 Notes	$	714,000	$	—		$	—	$	714,000
	Term Loan	298,500		—			—		298,500

Debt

Debt	12 Months Ended
	Dec. 31, 2014
Long-term Debt, Current and Noncurrent [Abstract]
Debt	Debt
	Our total debt is summarized as follows:
	(in thousands)		December 31, 2014			December 31, 2013
	Revolving credit facility under EXCO Resources Credit Agreement		$	202,492		$	763,866
	Term Loan under EXCO Resources Credit Agreement		—			298,500
	Unamortized discount on Term Loan		—			(2,780		)
	2018 Notes		750,000			750,000
	Unamortized discount on 2018 Notes		(5,957		)	(7,293		)
	2022 Notes		500,000			—
	Total debt excluding Compass		1,446,535			1,802,293
	Compass Production Partners Credit Agreement		—			88,485
	Total debt		1,446,535			1,890,778
	Less amounts due within one year		—			31,866
	Total debt due after one year		$	1,446,535		$	1,858,912
	Terms and conditions of each of these debt obligations are discussed below.
	EXCO Resources Credit Agreement
	As of December 31, 2014, the EXCO Resources Credit Agreement had $202.5 million of outstanding indebtedness, $900.0 million of available borrowing base and $690.9 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 175 bps to 275 bps (or alternate base rate ("ABR") plus 75 bps to 175 bps), depending on our borrowing base usage. On December 31, 2014, the one month LIBOR was 0.2%, which resulted in an interest rate of approximately 1.9% on the revolving commitment.
	We closed a rights offering and related private placement of our common shares on January 17, 2014 ("Rights Offering") and received gross proceeds of $272.9 million which we used to reduce the outstanding indebtedness under the EXCO Resources Credit Agreement, including the remainder of the asset sale requirement as well as a portion of the revolving commitment. See further discussion in "Note 13. Rights offering and other equity transactions". Upon repayment of the asset sale requirement, the interest rate on the revolving commitment decreased by 100 basis points.
	On April 16, 2014, we closed an offering of $500.0 million in aggregate principal amount of senior unsecured notes and utilized the proceeds to fully repay the Term Loan. The remaining proceeds were used to reduce outstanding indebtedness under the revolving commitment of the EXCO Resources Credit Agreement. See further discussion of the 2022 Notes below.
	On October 31, 2014 we closed the sale of our entire interest in Compass. The transaction resulted in a reduction to our consolidated indebtedness by our proportionate share of Compass's indebtedness, which at closing was $83.2 million. In addition, we used a portion of our proceeds from this transaction to reduce the outstanding indebtedness under the EXCO Resources Credit Agreement. Compass was not a guarantor to the EXCO Resources Credit Agreement, 2018 Notes or the 2022 Notes. As such, our borrowing base was not affected by this sale. See further discussion in "Note 3. Acquisitions, divestitures, and other significant events".
	On February 6, 2015, we amended the EXCO Resources Credit Agreement which decreased our borrowing base from $900.0 million to $725.0 million as a result of the recent decline in oil and natural gas prices. The next borrowing base redetermination for the EXCO Resources Credit Agreement will occur in August 2015. Subsequent redeterminations will occur semi-annually with us and the lenders having the right to request interim unscheduled redeterminations in certain circumstances. In addition, the financial covenants were amended to include an interest coverage ratio and senior secured indebtedness to consolidated EBITDAX ratio. The leverage ratio was suspended until the fourth quarter of 2016 and the ratio requirements thereafter were modified.
	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. We repurchased 38,821 shares for $0.1 million in 2014 that were tendered by employees to satisfy minimum tax withholding amounts for restricted share awards. There were no share repurchases during 2013 and 2012.
	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.
	The EXCO Resources Credit Agreement sets forth the terms and conditions under which we are permitted to pay a cash dividend on our common shares. In July 2014, we amended the EXCO Resources Credit Agreement to provide that we may declare and pay cash dividends on our common shares in an amount not to exceed a cumulative total of $75.0 million in any four consecutive fiscal quarters, provided that, as of each payment date and after giving effect to the dividend payment date, (i) no default has occurred and is continuing, (ii) we have at least 10% of our revolving commitment, as defined in the EXCO Resources Credit Agreement, available under the EXCO Resources Credit Agreement, and (iii) payment of such dividend is permitted under the indenture governing the 2018 Notes and 2022 Notes.
	As of December 31, 2014, we were in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which required that we:
	•	maintain a consolidated current ratio (as defined in the EXCO Resources Credit Agreement) of at least 1.0 to 1.0 as of the end of any fiscal quarter; and
	•	not permit our ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the EXCO Resources Credit Agreement) to be greater than 4.5 to 1.0 at the end of any fiscal quarter.
	On February 6, 2015, we amended the EXCO Resources Credit Agreement which requires 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 2.0 to 1.0 as of the end of any fiscal quarter;
	•	not permit our ratio of senior secured indebtedness to consolidated EBITDAX ("Secured Indebtedness Ratio") to be greater than 2.50 to 1.0 as of the end of any fiscal quarter; and
	•	not permit our ratio of consolidated funded indebtedness to consolidated EBITDAX ("Leverage Ratio") as of the end of any fiscal quarter to be greater than the ratio set forth for the following periods:
	Period		Ratio
	The fiscal quarter ending December 31, 2016		6.00 to 1.00
	The fiscal quarter ending March 31, 2017 and June 30, 2017		5.75 to 1.00
	The fiscal quarter ending September 30, 2017		5.25 to 1.00
	The fiscal quarter ending December 31, 2017		4.75 to 1.00
	Each fiscal quarter ending thereafter		4.50 to 1.00
	The Leverage Ratio will be calculated based on the consolidated EBITDAX for the trailing four quarter period ending on the last day of such fiscal quarter, except, the consolidated EBITDAX for quarter period ending December 31, 2016 shall be consolidated EBITDAX for quarter ending December 31, 2016 multiplied by 4.00, consolidated EBITDAX for the two quarter period ending March 31, 2017 shall be consolidated EBITDAX for such period multiplied by 2.00, and consolidated EBITDAX for the three quarter period ending June 30, 2017 shall be consolidated EBITDAX for such period multiplied by 4/3.
	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.
	As of December 31, 2014, $750.0 million in principal was outstanding on the 2018 Notes. The unamortized discount on the 2018 Notes at December 31, 2014 was $6.0 million. 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.
	2022 Notes
	On April 16, 2014, we completed a public offering of $500.0 million in aggregate principal amount of senior unsecured notes due April 15, 2022. We received net proceeds of approximately $490.0 million after offering fees and expenses. 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. We used a portion of the net proceeds from the 2022 Notes offering to repay the $297.8 million outstanding principal balance on the Term Loan and the remaining proceeds were used to reduce outstanding indebtedness under the revolving commitment of the EXCO Resources Credit Agreement.
	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.
	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 2015 and into 2016, 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, 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. Further, failing to comply with the financial and other restrictive covenants in the EXCO Resources Credit Agreement, 2018 Notes and 2022 Notes could result in an event of default, which could adversely affect our business, financial condition and results of operations.

Environmental_Regulation

Environmental Regulation	12 Months Ended
	Dec. 31, 2014
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, 2014
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, 2014. The commitments do not include those of our equity method investments. Gathering and firm transportation services presented in the following tables represent our gross commitments under these contracts and a portion of these costs will be incurred by working interest and other owners.
	(in thousands)	Gathering and firm transportation services			Other fixed commitments		Drilling contracts		Operating leases and other		Total
	2015	$	136,040		$	17,332	$	22,191	$	5,912	$	181,475
	2016	133,429			13,253		2,538		5,223		154,443
	2017	132,860			5,443		—		3,847		142,150
	2018	129,140			3,210		—		3,094		135,444
	2019	89,060			2,403		—		3,051		94,514
	Thereafter	101,618			3,530		—		1,623		106,771
	Total	$	722,147		$	45,171	$	24,729	$	22,750	$	814,797
	We lease our offices and certain equipment. Our rental expenses were approximately $5.1 million, $5.9 million and $6.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. We have also entered into various drilling rig contracts primarily to develop our Haynesville and Eagle Ford shale assets. 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.
	We have entered into firm transportation and gathering agreements with pipeline companies to facilitate sales from our East Texas/North Louisiana production and report these costs as a component of gathering and transportation expenses. At December 31, 2014, our firm transportation and gathering agreements covered the following gross volumes of natural gas:
	(in Bcf)	Firm transportation services		Gathering services
	2015	293		110
	2016	272		110
	2017	269		110
	2018	269		100
	2019	269		—
	Thereafter	299		—
	Total	1,671		430
	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.
	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, natural gas and NGLs produced and 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 do not believe that any resulting liability from any additional existing legal proceedings, individually or in the aggregate, will have a material adverse effect on our results of operations or financial condition and have properly reflected any potential exposure in our financial position when determined to be both probable and estimable.

Employee_Benefit_Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2014
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 match 100% of employee contributions. Our matching contributions were $7.1 million, $8.8 million and $9.4 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Earnings_Per_Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013 and 2012:
		Year Ended December 31,
	(in thousands, except per share data)	2014		2013		2012
	Basic net income (loss) per common share:
	Net income (loss)	$	120,669	$	22,204	$	(1,393,285	)
	Weighted average common shares outstanding	268,258		215,011		214,321
	Net income (loss) per basic common share	$	0.45	$	0.1	$	(6.50	)
	Diluted net income (loss) per common share:
	Net income (loss)	$	120,669	$	22,204	$	(1,393,285	)
	Weighted average common shares outstanding	268,258		215,011		214,321
	Dilutive effect of:
	Stock options	—		—		—
	Restricted shares and restricted share units	118		420		—
	Subscription rights	—		15,481		—
	Weighted average common shares and common share equivalents outstanding	268,376		230,912		214,321
	Net income (loss) per diluted common share	$	0.45	$	0.1	$	(6.50	)
	The computation of diluted EPS excluded 14,316,409, 55,524,191 and 17,242,306 antidilutive common share equivalents for the years ended December 31, 2014, 2013 and 2012, respectively. The antidilutive common share equivalents for the year ended December 31, 2014 and 2012 primarily related to out-of-the-money stock options, unvested restricted share units and unvested restricted share awards. The antidilutive common share equivalents for the year ended December 31, 2013 primarily consisted of subscription rights outstanding, out-of-the-money stock options and unvested restricted shares.

Stock_Options_And_Awards

Stock Options And Awards	12 Months Ended
	Dec. 31, 2014
Share-based Compensation [Abstract]
Stock options and awards	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, 2014 and 2013, there were 19,763,916 and 21,118,292 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.
	Compensation costs
	We account for our stock-based options and awards in accordance with ASC 718. 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 be recognized on unvested options, restricted share awards and restricted share units as of December 31, 2014 was $20.4 million. Of this amount, $3.1 million related to unvested options and will be recognized over a weighted average period of 1.7 years and $17.3 million related to unvested restricted share units and awards will be recognized over a weighted average period of 2.2 years.
	The following is a reconciliation of our share-based compensation expense for the years ended December 31, 2014, 2013 and 2012:
			Year Ended December 31,
	(in thousands)		2014				2013			2012
	Share-based compensation expense		$	4,962			$	10,748		$	8,926
	Share-based compensation capitalized		5,498				7,288			7,513
	Total share-based compensation		$	10,460			$	18,036		$	16,439
	We did not recognize a tax benefit attributable to our share-based compensation for the years ended December 31, 2014, 2013 and 2012.
	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 3.7 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, 2014, 2013 and 2012:
				Stock Options			Weighted average exercise price per share			Weighted average remaining terms (in years)		Aggregate intrinsic value
		Options outstanding at December 31, 2011		15,670,168			$	13.44
		Granted		146,500			8
		Forfeitures		(1,543,933	)		16.12
		Exercised		(256,940	)		7.66
		Options outstanding at December 31, 2012		14,015,795			13.2
		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		3.7		$	—
		Options exercisable at December 31, 2014		9,181,306			$	13.15		3.2		$	—
	The weighted average fair value of stock options on the date of the grant during the years ended December 31, 2014, 2013 and 2012 was $2.23, $3.53 and $3.96, respectively. The total intrinsic value of stock options exercised for the years ended December 31, 2014, 2013 and 2012 was $0.0 million, $0.2 million and $0.1 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. The following assumptions were used for the options included in the table above, for the years ended December 31:
			2014		2013		2012
	Expected life		7.5 years		3.8 to 7.5 years		3.8 to 7.5 years
	Risk-free rate of return		2.25 - 2.61 %		0.48 - 2.49 %		0.56 - 1.64 %
	Volatility		59.46 - 59.61 %		49.47 - 59.86 %		57.34 - 60.24 %
	Dividend yield		3.36 - 4.34 %		2.27 - 3.87 %		0.52 - 1.92 %
	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, 2014, 2013 and 2012 are as follows:
				Shares			Weighted average grant date fair value per share
		Non-vested shares outstanding at December 31, 2011		2,562,409			$	11.72
		Granted		926,900			7.57
		Vested		(370,448	)		12.89
		Forfeited		(312,496	)		11.89
		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			5.2
		Vested		(1,109,866	)		9.79
		Forfeited		(280,301	)		6.89
		Non-vested shares outstanding at December 31, 2014		1,877,929			$	6.4
	Market-based restricted share awards
	On August 13, 2013, EXCO’s officers were granted a market-based restricted share award. The total number of shares granted was 736,000 of which 368,000 will be vested following any 30 consecutive trading days in which the company’s common stock equals or exceeds $10.00 per share and 368,000 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"). Shares vest over a two year period and are subject to other vesting provisions depending on when the attainment date occurs. No such awards were granted in 2014.
	During the third quarter of 2014, EXCO's officers were granted 820,317 restricted share units which have a vesting percentage between 0% and 200% depending on EXCO's total shareholder return ("TSR") 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.
	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, 2014 and 2013 is as follows:
			Target Price Awards						TSRs
			Shares			Weighted average grant date fair value per share			Shares			Weighted average grant date fair value per share
	Non-vested shares outstanding at December 31, 2012		—			$	—		—			$	—
	Granted		736,000			6.36			—			—
Vested		—			—			—			—
Forfeited		(261,400	)		6.36			—			—
Non-vested shares outstanding at December 31, 2013		474,600			$	6.36		—			$	—
Granted		—			—			820,317			7.33
Vested		—			—			—			—
Forfeited		(73,200	)		6.36			(104,167	)		7.33
Non-vested shares outstanding at December 31, 2014		401,400			$	6.36		716,150			$	7.33

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013 and 2012, consisted of the following:
		Year ended December 31,
	(in thousands)	2014			2013			2012
	Current:
	Federal	$	—		$	—		$	—
	State	—			—			—
	Total current income tax (benefit)	$	—		$	—		$	—
	Deferred:
	Federal	$	45,797		$	25,626		$	(485,543	)
	State	18,960			3,239			(59,406		)
	Valuation allowance	(64,757		)	(28,865		)	544,949
	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 2027 and 2034. NOLs and alternative minimum tax credits available for utilization as of December 31, 2014 were approximately $2.0 billion and $1.5 million, respectively. In addition, 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. Significant components of our deferred tax liabilities and assets are as follows:
	(in thousands)	31-Dec-14			31-Dec-13
	Current deferred tax assets (liabilities):
	Derivative financial instruments	$	(38,519	)	$	—
	Other	2,584			5,332
	Valuation allowance	—			(5,332		)
	Net current deferred tax assets (liabilities)	(35,935		)	—
	Non-current deferred tax assets:
	Net operating loss and AMT credits carryforwards	$	781,899		$	737,399
	Capital loss carryforwards	40,356			—
	Share-based compensation	14,856			16,060
	Oil and natural gas properties, gathering assets, and equipment	—			47,491
	Goodwill	5,419			9,812
	Derivative financial instruments	—			2,102
	Investment in partnerships	72,988			73,328
	Other	84			85
	Total non-current deferred tax assets	915,602			886,277
	Valuation allowance	(826,852		)	(886,277		)
	Total non-current deferred tax assets	88,750			—
	Non-current deferred tax liabilities:
	Oil and natural gas properties, gathering assets, and equipment	$	(51,961	)	$	—
	Derivative financial instruments	(854		)	—
	Total non-current deferred tax liabilities	(52,815		)	—
	Net non-current deferred tax assets (liabilities)	$	35,935		$	—
	The reversal of the temporary differences related to the net current deferred tax liability is expected to be offset by taxable losses generated in the same fiscal year as the reversal. If we do not generate taxable losses in the same fiscal year to offset the reversal of the temporary differences then we will utilize our NOLs to offset the taxable income.
	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, 2014, 2013 and 2012 is presented in the following table:
		Year Ended December 31,
	(in thousands)	2014			2013			2012
	Federal income taxes (benefit) provision at statutory rate of 35%	$	42,234		$	7,772		$	(487,649	)
	Increases (reductions) resulting from:
	Goodwill	—			16,382			—
	Adjustments to the valuation allowance	(64,757		)	(28,865		)	544,949
	Non-deductible compensation	3,409			1,328			1,893
	State taxes net of federal benefit	3,464			3,239			(59,406		)
	State tax rate change	15,496			—			—
	Other	154			144			213
	Total income tax provision	$	—		$	—		$	—
	During both 2014 and 2013, both federal and state income taxes were reduced to zero by a corresponding decrease to the valuation allowance previously recognized against net deferred tax assets. The net result was no income tax provision for both 2014 and 2013.
	During 2012, our net loss was greatly impacted by the impairments of our proved oil and natural gas properties and the recognized valuation allowance almost completely offset the impairments. There were no material sales transactions during the year to impact taxable income. The net result was no income tax provision for 2012.
	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, 2014, 2013 and 2012, 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. We do not anticipate that the remaining tax exam on the pass-through entity will result in a material change to the tax return as originally filed.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related party transactions	Related party transactions
	OPCO serves as the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis. 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, 2014, 2013 and 2012 these transactions included the following:
			Year Ended December 31,
	(in thousands)		2014		2013		2012
	Advances to OPCO		$	—	$	28,378	$	76,729
	Amounts received from OPCO		53,002		43,632		52,206
	As of December 31, 2014 and 2013, the amounts owed under the service agreements were as follows:
	(in thousands)		31-Dec-14		31-Dec-13
	Amounts due to EXCO (1)		$	2,799	$	2,283
	Amounts due from EXCO (1)		—		—
	-1	OPCO is the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis, which are recorded in "Other current assets" on our 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 Consolidated Balance Sheets.
	Other related party transactions
	Investment accounts managed by Invesco Advisers, Inc. were lenders under the Term Loan of the EXCO Resources Credit Agreement. Invesco Advisers, Inc. is an indirect owner of WL Ross & Co. LLC ("WL Ross"). Wilbur L. Ross, Jr., the Chairman and Chief Executive Officer at WL Ross, serves on EXCO’s board of directors. Invesco Advisers, Inc. held approximately 10% of total borrowings under the Term Loan until the Term Loan was repaid in April 2014 with proceeds received from the issuance of the 2022 Notes.
	As discussed in "Note 15. 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 and Hamblin Watsa Investment Counsel Ltd. ("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.

Dividends

Dividends	12 Months Ended
	Dec. 31, 2014
Dividends [Abstract]
Dividends	Dividends
	Total dividends paid to our shareholders in 2014, 2013 and 2012 were $41.1 million, $43.2 million, and $34.4 million, respectively. On December 15, 2014, our board of directors suspended the cash dividend and did not approve a cash dividend for the fourth quarter of 2014.
	Any future declaration of dividends, as well as the establishment of record and payment dates, will depend on our earnings, capital requirements, financial condition, prospects and other factors our board of directors may deem relevant.

Rights_Offering_and_other_equi

Rights Offering and other equity transactions	12 Months Ended
	Dec. 31, 2014
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 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 which is further discussed in "Note 6. Debt". 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. After giving effect to the Rights Offering, WL Ross and Hamblin Watsa owned 18.7% and 6.4%, respectively of the Company's outstanding common shares as of January 17, 2014.
	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_Financ

Condensed Consolidating Financial Statements	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed consolidating financial statements	Condensed consolidating financial statements
	As of December 31, 2014, the majority of EXCO’s subsidiaries were guarantors under the EXCO Resources Credit Agreement and the indenture governing the 2018 Notes and 2022 Notes. All of our non-guarantor subsidiaries were considered unrestricted subsidiaries under the indenture 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 and 2022 Notes, which were issued by EXCO Resources, Inc., are jointly and severally guaranteed by some 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, 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
	Gathering, office, field and other assets, net		1,269			23,375			—			—			24,644
	Investments in and advances to affiliates, net		1,746,931			—			—			(1,746,931		)	—
	Deferred financing costs, net		30,636			—			—			—			30,636
	Derivative financial instruments		2,138			—			—			—			2,138
	Goodwill		13,293			149,862			—			—			163,155
	Deferred income taxes		35,935			—			—			—			35,935
	Total assets		$	2,032,251		$	2,015,591		$	55,985		$	(1,746,931	)	$	2,356,896
	Liabilities and shareholders' equity
	Current liabilities		$	75,441		$	289,930		$	—		$	—		$	365,371
	Long-term debt		1,446,535			—			—			—			1,446,535
	Deferred income taxes		—			—			—			—			—
	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		$	2,032,251		$	2,015,591		$	55,985		$	(1,746,931	)	$	2,356,896
	EXCO RESOURCES, INC.
	CONDENSED CONSOLIDATING BALANCE SHEET
	December 31, 2013
	(in thousands)		Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	Assets
	Current assets:
	Cash and cash equivalents		$	81,840		$	(35,892	)	$	4,535		$	—		$	50,483
	Restricted cash		—			20,570			—			—			20,570
	Other current assets		22,533			206,708			5,560			—			234,801
	Total current assets		104,373			191,386			10,095			—			305,854
	Equity investments		—			—			57,562			—			57,562
	Oil and natural gas properties (full cost accounting method):
	Unproved oil and natural gas properties and development costs not being amortized		6,758			415,290			3,259			—			425,307
	Proved developed and undeveloped oil and natural gas properties		337,972			3,097,335			118,903			—			3,554,210
	Accumulated depletion		(330,086		)	(1,840,332		)	(13,046		)	—			(2,183,464		)
	Oil and natural gas properties, net		14,644			1,672,293			109,116			—			1,796,053
	Gathering, office, field and other assets, net		3,481			24,639			22,248			—			50,368
	Investments in and advances to affiliates, net		1,834,197			—			—			(1,834,197		)	—
	Deferred financing costs, net		27,771			—			1,036			—			28,807
	Derivative financial instruments		6,829			—			—			—			6,829
	Goodwill		13,293			149,862			—			—			163,155
	Total assets		$	2,004,588		$	2,038,180		$	200,057		$	(1,834,197	)	$	2,408,628
	Liabilities and shareholders' equity
Current liabilities		$	76,174		$	264,485		$	8,511		$	—		$	349,170
Long-term debt		1,770,427			—			88,485			—			1,858,912
Deferred income taxes		—			—			—			—			—
Other long-term liabilities		10,082			33,831			8,728			—			52,641
Payable to parent		—			2,230,108			35,777			(2,265,885		)	—
Total shareholders' equity		147,905			(490,244		)	58,556			431,688			147,905
Total liabilities and shareholders' equity		$	2,004,588		$	2,038,180		$	200,057		$	(1,834,197	)	$	2,408,628
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 OPERATIONS
For the year ended December 31, 2012
(in thousands)		Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas		$	78,649		$	467,960		$	—		$	—		$	546,609
Costs and expenses:
Oil and natural gas production		19,820			84,790			—			—			104,610
Gathering and transportation		—			102,875			—			—			102,875
Depletion, depreciation and amortization		7,767			295,389			—			—			303,156
Impairment of oil and natural gas properties		—			1,346,749			—			—			1,346,749
Accretion of discount on asset retirement obligations		526			3,361			—			—			3,887
General and administrative		14,394			69,424			—			—			83,818
Other operating items		(194		)	17,223			—			—			17,029
Total costs and expenses		42,313			1,919,811			—			—			1,962,124
Operating income (loss)		36,336			(1,451,851		)	—			—			(1,415,515		)
Other income:
Interest expense, net		(73,489		)	(3		)	—			—			(73,492		)
Gain on derivative financial instruments		62,812			3,321			—			—			66,133
Other income		238			731			—			—			969
Equity income		—			—			28,620			—			28,620
Net loss from consolidated subsidiaries		(1,419,182		)	—			—			1,419,182			—
Total other income (expense)		(1,429,621		)	4,049			28,620			1,419,182			22,230
Income (loss) before income taxes		(1,393,285		)	(1,447,802		)	28,620			1,419,182			(1,393,285		)
Income tax expense		—			—			—			—			—
Net income (loss)		$	(1,393,285	)	$	(1,447,802	)	$	28,620		$	1,419,182		$	(1,393,285	)
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		)
Restricted cash		—			(3,400		)	—			—			(3,400		)
Equity method investments		—			1,749			—			—			1,749
Proceeds from disposition of property and equipment		99,612			95,594			(7,551		)	—			187,655
Distributions received from Compass		5,856			—			—			(5,856		)	—
Net changes in advances to joint ventures		—			(5,026		)	—			—			(5,026		)
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		(10,188		)	—			(102		)	—			(10,290		)
Payments of common shares repurchased		(136		)	—			—			—			(136		)
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 and property acquisitions		(15,767		)	(1,242,667		)	(38,818		)	—			(1,297,252		)
Restricted cash		—			49,515			—			—			49,515
Equity method investments		—			236,289			—			—			236,289
Proceeds from disposition of property and equipment		244,500			505,128			—			—			749,628
Distributions from Compass		3,825			—			—			(3,825		)	—
Net changes in advances to joint ventures		—			10,645			—			—			10,645
Advances/investments with affiliates		(59,575		)	59,575			—			—			—
Other		(1,303		)	—			—			—			(1,303		)
Net cash provided by (used in) investing activities		171,680			(381,515		)	(38,818		)	(3,825		)	(252,478		)
Financing Activities:
Borrowings under credit agreements		967,766			—			36,757			—			1,004,523
Repayments under 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
EXCO RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the year ended December 31, 2012
(in thousands)		Resources			Guarantor Subsidiaries			Non-guarantor subsidiaries			Eliminations			Consolidated
Operating Activities:
Net cash provided by operating activities		$	182,143		$	332,643		$	—		$	—		$	514,786
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment		(77,006		)	(459,917		)	—			—			(536,923		)
Restricted cash		—			85,840			—			—			85,840
Equity method investments		—			(14,907		)	—			—			(14,907		)
Proceeds from disposition of property and equipment		15,161			22,884			—			—			38,045
Net changes in advances to joint ventures		—			851			—			—			851
Advances/investments with affiliates		(59,126		)	59,126			—			—			—
Net cash used in investing activities		(120,971		)	(306,123		)	—			—			(427,094		)
Financing Activities:
Borrowings under the credit agreements		53,000			—			—			—			53,000
Repayments under the credit agreements		(93,000		)	—			—			—			(93,000		)
Proceeds from issuance of common shares, net		1,968			—			—			—			1,968
Payment of common share dividends		(34,358		)	—			—			—			(34,358		)
Deferred financing costs and other		(1,655		)	—			—			—			(1,655		)
Net cash used in financing activities		(74,045		)	—			—			—			(74,045		)
Net increase (decrease) in cash		(12,873		)	26,520			—			—			13,647
Cash at beginning of period		78,664			(46,667		)	—			—			31,997
Cash at end of period		$	65,791		$	(20,147	)	$	—		$	—		$	45,644

Quarterly_Financial_Data_unaud

Quarterly Financial Data (unaudited)	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013:
			Quarter
	(in thousands, except per share amounts)		1st			2nd		3rd			4th
	2014
	Oil and natural gas revenues		$	198,472		$	182,966	$	151,042		$	127,789
	Operating income (loss)		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		$	0.3
	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		$	0.3
	Weighted average shares		260,716			271,226		272,066			271,053
	2013
	Oil and natural gas revenues		$	138,223		$	150,332	$	165,314		$	180,440
	Operating income (loss) (1)		209,075			33,883		15,594			(79,331		)
	Net income (loss) (2) (3)		$	158,120		$	85,598	$	(98,651	)	$	(122,863	)
	Basic earnings (loss) per share:
	Net income (loss)		$	0.74		$	0.4	$	(0.46	)	$	(0.57	)
	Weighted average shares		214,784			214,788		215,056			215,410
	Diluted earnings (loss) per share:
	Net income (loss)		$	0.74		$	0.4	$	(0.46	)	$	(0.57	)
	Weighted average shares		214,861			216,023		215,056			215,410
	-1	Operating income (loss) for the first quarter and the fourth quarter of 2013 includes $10.7 million and $97.8 million, respectively, of impairments of oil and natural gas properties. See "Note 2. Summary of significant accounting policies" for further discussion.
	-2	Net income (loss) for the third quarter of 2013 includes a $91.5 million impairment to our investment in TGGT as a result of the carrying value exceeding the fair value. The impairment was reduced by $4.7 million in the fourth quarter of 2013 to $86.8 million as a result of final closing adjustments, fees and transaction expenses related to the sale of our equity investment in TGGT. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion.
	-3	Net income (loss) for the first quarter of 2013 includes a gain of $187.0 million from our contribution of oil and natural gas properties to Compass. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion.

Supplemental_Information_Relat

Supplemental Information Relating To Oil And Natural Gas Producing Activities (unaudited)	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013 and 2012 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
	2014:00:00
	Proved property acquisition costs		$	10,562
	Unproved property acquisition costs		—
	Total property acquisition costs		10,562
	Development		354,199
	Exploration costs (1)		5,906
	Lease acquisitions and other		9,681
	Capitalized asset retirement costs		576
	Depletion per Boe		$	11.42
	Depletion per Mcfe		$	1.9
	2013:00:00
	Proved property acquisition costs		$	754,370
	Unproved property acquisition costs		232,020
	Total property acquisition costs (2)		986,390
	Development		231,447
	Exploration costs (3)		38,579
	Lease acquisitions and other		14,835
	Capitalized asset retirement costs		514
	Depletion per Boe		$	8.82
	Depletion per Mcfe		$	1.47
	2012:00:00
	Proved property acquisition costs		$	—
	Unproved property acquisition costs		3,349
	Total property acquisition costs		3,349
	Development		346,017
	Exploration costs (4)		57,325
	Lease acquisitions and other (5)		44,546
	Capitalized asset retirement costs		971
	Depletion per Boe		$	9.11
	Depletion per Mcfe		$	1.52
	-1	Exploration costs in 2014 include $5.9 million in the Bossier shale in North Louisiana.
	-2	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.
	-3	Exploration costs in 2013 include $29.2 million in the Eagle Ford shale and $9.4 million in the Marcellus shale.
	-4	Exploration costs in 2012 include $40.1 million in the Haynesville shale $17.2 million in the Marcellus shale.
	-5	Lease acquisition costs in 2012 are net of acreage reimbursements from BG Group totaling $2.1 million.
	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			Natural Gas Liquids (Mbbls)			Mmcfe (11)
			(Mbbls)			Gas
						(Mmcf)
	December 31, 2011		6,354			1,291,464			—			1,329,588
	Purchase of reserves in place		—			—			—			—
	Discoveries and extensions (1)		492			96,615			424			102,111
	Revisions of previous estimates:
	Changes in price		(110	)		(466,238	)		—			(466,898	)
	Other factors (2)		(463	)		199,784			6,724			237,350
	Sales of reserves in place		—			(2,837	)		—			(2,837	)
	Production		(703	)		(182,656	)		(509	)		(189,928	)
	December 31, 2012		5,570			936,132			6,639			1,009,386
	Purchase of reserves in place (3)		16,022			290,933			2,201			400,271
	Discoveries and extensions (4)		5,960			46,834			513			85,672
	Revisions of previous estimates:
	Changes in price		457			272,614			686			279,472
	Other factors (5)		(3,219	)		(106,695	)		(741	)		(130,455	)
	Sales of reserves in place (6)		(8,224	)		(270,018	)		(6,472	)		(358,194	)
	Production		(1,188	)		(153,321	)		(243	)		(161,907	)
	31-Dec-13		15,378			1,016,479			2,583			1,124,245
	Purchase of reserves in place (7)		—			7,316			—			7,316
	Discoveries and extensions (8)		4,164			69,902			107			95,528
	Revisions of previous estimates:
Changes in price		45			167,302			127			168,334
Other factors (9)		1,737			120,850			(8	)		131,224
Sales of reserves in place (10)		(1,401	)		(105,841	)		(2,144	)		(127,111	)
Production		(2,236	)		(120,980	)		(224	)		(135,740	)
31-Dec-14		17,687			1,155,028			441			1,263,796
Estimated Quantities of Proved Developed and Proved Undeveloped Reserves
		Oil			Natural			Natural Gas Liquids (Mbbls)			Mmcfe
		(Mbbls)			Gas
					(Mmcf)
Proved developed:
December 31, 2014		14,429			502,314			387			591,210
December 31, 2013		11,274			657,116			2,088			737,291
December 31, 2012		4,371			917,326			4,784			972,256
Proved undeveloped:
December 31, 2014		3,258			652,714			54			672,586
December 31, 2013		4,104			359,363			495			386,954
December 31, 2012		1,199			18,806			1,855			37,130
-1	New discoveries and extensions in 2012 include 25,626 Mmcfe in East Texas/North Louisiana, primarily in the Haynesville shale, 59,455 Mmcfe in the Marcellus shale and 17,027 Mmcfe in the Permian Basin.
-2	Total revisions due to Other factors in 2012 include approximately 8,736 Mmcfe of Proved Undeveloped Reserves that were reclassified to unproved reserves as a result of a slower development schedule due to depressed natural gas prices, which extended their scheduled development beyond a five-year development horizon. The change also includes a positive revision of 246,451 Mmcfe resulting from unproved performance and cost reductions.
-3	Purchases of reserves in place include 115,718 Mmcfe in the Eagle Ford shale, 259,991 Mmcfe in the Haynesville shale, and 24,558 Mmcfe for our proportionate share of Compass's acquisition of shallow Cotton Valley assets in East Texas/North Louisiana.
-4	New discoveries and extensions in 2013 include 36,501 Mmcfe in the Eagle Ford shale, 33,591 Mmcfe in the Marcellus shale, 10,211 Mmcfe in the Haynesville shale, 3,881 Mmcfe for conventional properties held by Compass in the Permian Basin, and 1,486 Mmcfe for shale properties in the Permian Basin.
-5	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.
-6	Sales of reserves in place in 2013 include 327,608 Mmcfe as a result of our contribution of properties to Compass and 30,582 Mmcfe from the sale of undeveloped properties in the Eagle Ford in connection with the Participation Agreement.
-7	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.
-8	New discoveries and extensions in 2014 included 48,698 Mmcfe in the Haynesville shale, 26,148 Mmcfe in the Eagle Ford Shale and 19,664 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.
-9	Total revisions due to Other factors include upward revisions of approximately 67,095 Mmcfe in the Shelby area, approximately 45,878 Mmcfe in the Appalachia region, and approximately 5,836 Mmcfe in the Holly area. The upward revisions were primarily due to improved well performance resulting from enhanced well designs and completion techniques.
-10	Sales of reserves in place in 2014 consist primarily of the sale of our entire interest in Compass.
-11	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, natural gas and NGL 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, 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
Year ended December 31, 2012:
Future cash inflows		$	3,187,480
Future production costs		1,824,702
Future development costs		266,726
Future income taxes		—
Future net cash flows		1,096,052
Discount of future net cash flows at 10% per annum		399,905
Standardized measure of discounted future net cash flows		$	696,147
During recent years, prices paid for oil and natural gas have fluctuated significantly. The reference prices at December 31, 2014, 2013 and 2012 used in the above table, were $94.99, $96.78 and $94.71 per Bbl of oil, respectively, and $4.35, $3.67 and $2.76 per Mmbtu of natural gas, respectively. The reference price at December 31, 2014, 2013 and 2012 used in the above table was $33.03 $39.92 and $46.57 per Bbl for NGLs, 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, West Texas Intermediate crude oil at Cushing, Oklahoma, and the trailing 12 month average of realized prices for NGLs.
The following are the principal sources of change in the Standardized Measure:
(in thousands)		Amount
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
Year ended December 31, 2012:
Sales and transfers of oil and natural gas produced		$	(339,125	)
Net changes in prices and production costs		(1,258,493		)
Extensions and discoveries, net of future development and production costs		90,633
Development costs during the period		204,929
Changes in estimated future development costs		404,414
Revisions of previous quantity estimates		(336,142		)
Sales of reserves in place		(3,604		)
Purchase of reserves in place		—
Accretion of discount before income taxes		165,755
Changes in timing and other		94,129
Net change in income taxes		247,189
Net change		$	(730,315	)
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				2014				2013			2012		2011 and
															prior
Property acquisition costs		$	228,553			$	9,737			$	71,524		$	3,038	$	144,254
Exploration and development		16,366				10,797				73			524		4,972
Capitalized interest		31,106				11,871				8,737			6,796		3,702
Total		$	276,025			$	32,405			$	80,334		$	10,358	$	152,928

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013 and the Consolidated Statements of Operations, Consolidated Statements of Cash Flows and Changes in Shareholders' Equity for the years ended December 31, 2014, 2013 and 2012. 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, share-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/North Louisiana. Funds held in this escrow account are restricted and can be used primarily for drilling and operations in East Texas/North Louisiana.
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, 2014 and 2013. 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 $276.0 million and $425.3 million as of December 31, 2014 and 2013, 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. 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 this evaluation, we did not record an impairment of undeveloped properties during 2014 and recorded impairments of $1.0 million and $60.8 million of undeveloped properties during 2013 and 2012, respectively. These impairments were transferred to the depletable portion of the full cost pool during each year. The impairments were recorded to reflect the estimated market price which included certain properties that were no longer part of our drilling plans.
	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 is computed using the simple average spot price for the trailing 12 month period using the first day of each month. For the 12 months ended December 31, 2014, the trailing 12 month reference prices were $4.35 per Mmbtu for natural gas at Henry Hub ("HH"), and $94.99 per Bbl of oil for West Texas Intermediate ("WTI") at Cushing, Oklahoma. Each of the reference prices for oil and natural gas are further adjusted for quality factors and regional differentials to derive estimated future net revenues. The price used for NGLs was $33.03 per Bbl and was based on the trailing 12 month average of realized prices. 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 ceiling test limitation exceeded the book value of the full cost pool as of December 31, 2014.
	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.
Office, field and other equipment	Office, field and other equipment
	Office, field and other equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives ranging from 3 to 15 years.
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. Losses, if any, resulting from impairment tests will be reflected in operating income 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 also consider our market capitalization in our evaluation of the fair value of our business.
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)		2014			2013			2012
	Asset retirement obligations at beginning of period		$	42,954		$	61,864		$	58,088
	Activity during the period:
	Liabilities incurred during the period		576			514			971
	Revisions in estimated assumptions		—			1,268			—
	Liabilities settled during the period		(33		)	(187		)	(338		)
	Adjustment to liability due to acquisitions		107			5,566			—
	Adjustment to liability due to divestitures (1)		(9,539		)	(28,585		)	(744		)
	Accretion of discount		2,690			2,514			3,887
	Asset retirement obligations at end of period		36,755			42,954			61,864
	Less current portion		1,769			191			1,200
	Long-term portion		$	34,986		$	42,763		$	60,664
	-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 have no 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. Due to these two distinct selling arrangements, 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 $13.5 million, $10.5 million and $20.5 million for the years ended December 31, 2014, 2013 and 2012, 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 $6.4 million, $5.8 million and $10.3 million for the years ended December 31, 2014, 2013 and 2012, 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 certain properties in the East Texas/North Louisiana JV and the Appalachia JV. 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 will provide certain transition services to Compass for up to nine months following the closing date. For the years ended December 31, 2014, 2013 and 2012, general and administrative expenses were reduced by $24.7 million, $26.8 million and $25.2 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.
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 and restricted share awards. 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 and restricted share awards, 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".
Share-based compensation	Share-based compensation
	We account for our share-based compensation in accordance with FASB ASC Topic 718, Compensation-Stock Compensation ("ASC 718"). 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 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity ("ASU 2014-08"). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity's operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. ASU 2014-08 also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant component of an entity that does not qualify for discontinued operations reporting. ASU 2014-08 retained the scope exception for oil and natural gas properties accounted for under the full-cost method and therefore we do not believe the update will have a significant impact on our consolidated financial condition and results of operations. ASU 2014-08 is effective prospectively to all periods beginning after December 15, 2014. We will apply the guidance prospectively to disposal activity, when applicable, occurring after the effective date of ASU 2014-08.
	In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) ("ASU 2014-09"). The FASB and the International Accounting Standards Board ("IASB") jointly issued this comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under GAAP. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under currently applicable guidance, including identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016 and permits the use of either the retrospective or cumulative effect transition method. We are currently assessing the potential impact of ASU 2014-09 on our consolidated financial condition and results of operations.
	In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern ("ASU 2014-15"). ASU 2014-15 provides guidance about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and sets rules for how this information should be disclosed in the financial statements. ASU 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods thereafter. Early adoption is permitted. As discussed in "Note 6. Debt", our ability to maintain compliance with certain debt covenants might be negatively impacted when oil and/or natural gas prices and production declines over an extended period of time. If such event occurs in future periods that could affect our ability to continue as going concern, we will provide appropriate disclosures as required by ASU 2014-15.
Discontinued Operations	In April 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity ("ASU 2014-08"). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity's operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. ASU 2014-08 also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant component of an entity that does not qualify for discontinued operations reporting. ASU 2014-08 retained the scope exception for oil and natural gas properties accounted for under the full-cost method and therefore we do not believe the update will have a significant impact on our consolidated financial condition and results of operations. ASU 2014-08 is effective prospectively to all periods beginning after December 15, 2014. We will apply the guidance prospectively to disposal activity, when applicable, occurring after the effective date of ASU 2014-08.

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Reconciliation Of Asset Retirement Obligations	The following is a reconciliation of our asset retirement obligations for the periods indicated:
			December 31,
	(in thousands)		2014			2013			2012
	Asset retirement obligations at beginning of period		$	42,954		$	61,864		$	58,088
	Activity during the period:
	Liabilities incurred during the period		576			514			971
	Revisions in estimated assumptions		—			1,268			—
	Liabilities settled during the period		(33		)	(187		)	(338		)
	Adjustment to liability due to acquisitions		107			5,566			—
	Adjustment to liability due to divestitures (1)		(9,539		)	(28,585		)	(744		)
	Accretion of discount		2,690			2,514			3,887
	Asset retirement obligations at end of period		36,755			42,954			61,864
	Less current portion		1,769			191			1,200
	Long-term portion		$	34,986		$	42,763		$	60,664
	-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 have no assets that are legally restricted for purposes of settling asset retirement obligations.

Recovered_Sheet1

Divestitures, Acquisitions and Other Significant Events (Tables)	12 Months Ended
	Dec. 31, 2014
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
Business Acquisition, Pro Forma Information, Nonrecurring Adjustments	Pro forma results of operations - The following table reflects the unaudited pro forma results of operations as though the acquisition of the Haynesville and Eagle Ford assets had occurred on January 1, 2012:
			Year Ended December 31,
	(in thousands, except for per share data)		2013			2012
	Oil and natural gas revenues		$	784,628		$	715,286
	Net income (loss) (1)		$	38,663		$	(1,398,169	)
	Basic earnings (loss) per share		$	0.18		$	(6.52	)
	Diluted earnings (loss) per share		$	0.17		$	(6.52	)
	-1	Net loss for the year ended December 31, 2012 was primarily due to the impairment of our oil and natural gas properties due to the significant decline in natural gas prices.

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014				December 31, 2013
	Derivative financial instruments - Current assets	$	97,278			$	8,226
	Derivative financial instruments - Long-term assets	2,138				6,829
	Derivative financial instruments - Current liabilities	(892		)		(11,919		)
	Derivative financial instruments - Long-term liabilities	—				(9,671		)
	Net derivative financial instruments	$	98,524			$	(6,535	)
Effect Of Derivative Financial Instruments	The Effect of Derivative Financial Instruments
		Year Ended December 31,
	(in thousands)	2014				2013				2012
	Gain (loss) on derivative financial instruments	$	87,665			$	(320	)		$	66,133
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, 2014:
	(in thousands, except prices)	Volume Mmbtu/Bbl			Weighted average strike price per Mmbtu/Bbl				Fair value at December 31, 2014
	Natural gas:
	Swaps:
	2015	42,888			$	4.2			49,926
	Call options:
	2015	20,075			4.29				(784		)
	Three-way collars:
	2015	27,375							10,205
	Sold call				4.47
	Purchased put				3.83
	Sold put				3.33
	2016	10,980							2,138
	Sold call				4.8
	Purchased put				3.9
	Sold put				3.4
	Total natural gas								$	61,485
	Oil:
	Swaps:
	2015	1,095			$	91.09			36,797
	Basis swaps:
	2015	91			6.1				350
	Call options:
	2015	365			100				(108		)
	Total oil								$	37,039
	Total oil and natural gas derivative financial instruments								$	98,524

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Summary Of Estimated Fair Value Of Derivative Financial Instruments
		December 31, 2014
	(in thousands)	Level 1		Level 2			Level 3		Total
	Oil and natural gas derivative financial instruments	$	—	$	98,524		$	—	$	98,524
		December 31, 2013
	(in thousands)	Level 1		Level 2			Level 3		Total
	Oil and natural gas derivative financial instruments	$	—	$	(6,535	)	$	—	$	(6,535	)
Schedule Of Estimated Fair Value Of Other Financial Instruments
		December 31, 2014
	(in thousands)	Level 1		Level 2			Level 3		Total
	2018 Notes	$	558,750	$	—		$	—	$	558,750
	2022 Notes	373,500		—			—		373,500
		December 31, 2013
	(in thousands)	Level 1		Level 2			Level 3		Total
	2018 Notes	$	714,000	$	—		$	—	$	714,000
	Term Loan	298,500		—			—		298,500

Debt_Tables

Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Long-term Debt, Current and Noncurrent [Abstract]
Schedule Of Debt	Our total debt is summarized as follows:
	(in thousands)	December 31, 2014			December 31, 2013
	Revolving credit facility under EXCO Resources Credit Agreement	$	202,492		$	763,866
	Term Loan under EXCO Resources Credit Agreement	—			298,500
	Unamortized discount on Term Loan	—			(2,780		)
	2018 Notes	750,000			750,000
	Unamortized discount on 2018 Notes	(5,957		)	(7,293		)
	2022 Notes	500,000			—
	Total debt excluding Compass	1,446,535			1,802,293
	Compass Production Partners Credit Agreement	—			88,485
	Total debt	1,446,535			1,890,778
	Less amounts due within one year	—			31,866
	Total debt due after one year	$	1,446,535		$	1,858,912
Schedule of Long-term Debt Instruments	not permit our ratio of consolidated funded indebtedness to consolidated EBITDAX ("Leverage Ratio") as of the end of any fiscal quarter to be greater than the ratio set forth for the following periods:
	Period	Ratio
	The fiscal quarter ending December 31, 2016	6.00 to 1.00
	The fiscal quarter ending March 31, 2017 and June 30, 2017	5.75 to 1.00
	The fiscal quarter ending September 30, 2017	5.25 to 1.00
	The fiscal quarter ending December 31, 2017	4.75 to 1.00
	Each fiscal quarter ending thereafter	4.50 to 1.00

Commitments_And_Contingencies_

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014. The commitments do not include those of our equity method investments. Gathering and firm transportation services presented in the following tables represent our gross commitments under these contracts and a portion of these costs will be incurred by working interest and other owners.
	(in thousands)	Gathering and firm transportation services			Other fixed commitments		Drilling contracts		Operating leases and other		Total
	2015	$	136,040		$	17,332	$	22,191	$	5,912	$	181,475
	2016	133,429			13,253		2,538		5,223		154,443
	2017	132,860			5,443		—		3,847		142,150
	2018	129,140			3,210		—		3,094		135,444
	2019	89,060			2,403		—		3,051		94,514
	Thereafter	101,618			3,530		—		1,623		106,771
	Total	$	722,147		$	45,171	$	24,729	$	22,750	$	814,797
Oil and Gas Delivery Commitments and Contracts Disclosure	At December 31, 2014, our firm transportation and gathering agreements covered the following gross volumes of natural gas:
	(in Bcf)	Firm transportation services		Gathering services
	2015	293		110
	2016	272		110
	2017	269		110
	2018	269		100
	2019	269		—
	Thereafter	299		—
	Total	1,671		430

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013 and 2012:
		Year Ended December 31,
	(in thousands, except per share data)	2014		2013		2012
	Basic net income (loss) per common share:
	Net income (loss)	$	120,669	$	22,204	$	(1,393,285	)
	Weighted average common shares outstanding	268,258		215,011		214,321
	Net income (loss) per basic common share	$	0.45	$	0.1	$	(6.50	)
	Diluted net income (loss) per common share:
	Net income (loss)	$	120,669	$	22,204	$	(1,393,285	)
	Weighted average common shares outstanding	268,258		215,011		214,321
	Dilutive effect of:
	Stock options	—		—		—
	Restricted shares and restricted share units	118		420		—
	Subscription rights	—		15,481		—
	Weighted average common shares and common share equivalents outstanding	268,376		230,912		214,321
	Net income (loss) per diluted common share	$	0.45	$	0.1	$	(6.50	)

Stock_Options_And_Awards_Table

Stock Options And Awards (Tables)	12 Months Ended
	Dec. 31, 2014
Share-based Compensation [Abstract]
Reconciliation Of Share-Based Compensation Expense	The following is a reconciliation of our share-based compensation expense for the years ended December 31, 2014, 2013 and 2012:
			Year Ended December 31,
	(in thousands)		2014				2013			2012
	Share-based compensation expense		$	4,962			$	10,748		$	8,926
	Share-based compensation capitalized		5,498				7,288			7,513
	Total share-based compensation		$	10,460			$	18,036		$	16,439
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, 2014, 2013 and 2012:
				Stock Options			Weighted average exercise price per share			Weighted average remaining terms (in years)		Aggregate intrinsic value
		Options outstanding at December 31, 2011		15,670,168			$	13.44
		Granted		146,500			8
		Forfeitures		(1,543,933	)		16.12
		Exercised		(256,940	)		7.66
		Options outstanding at December 31, 2012		14,015,795			13.2
		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		3.7		$	—
		Options exercisable at December 31, 2014		9,181,306			$	13.15		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		2012
	Expected life		7.5 years		3.8 to 7.5 years		3.8 to 7.5 years
	Risk-free rate of return		2.25 - 2.61 %		0.48 - 2.49 %		0.56 - 1.64 %
	Volatility		59.46 - 59.61 %		49.47 - 59.86 %		57.34 - 60.24 %
	Dividend yield		3.36 - 4.34 %		2.27 - 3.87 %		0.52 - 1.92 %
Restricted Stock Activity	A summary of our service-based restricted share activity for the years ended December 31, 2014, 2013 and 2012 are as follows:
				Shares			Weighted average grant date fair value per share
		Non-vested shares outstanding at December 31, 2011		2,562,409			$	11.72
		Granted		926,900			7.57
		Vested		(370,448	)		12.89
		Forfeited		(312,496	)		11.89
		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			5.2
		Vested		(1,109,866	)		9.79
		Forfeited		(280,301	)		6.89
		Non-vested shares outstanding at December 31, 2014		1,877,929			$	6.4
	Market-based restricted share awards
	On August 13, 2013, EXCO’s officers were granted a market-based restricted share award. The total number of shares granted was 736,000 of which 368,000 will be vested following any 30 consecutive trading days in which the company’s common stock equals or exceeds $10.00 per share and 368,000 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"). Shares vest over a two year period and are subject to other vesting provisions depending on when the attainment date occurs. No such awards were granted in 2014.
	During the third quarter of 2014, EXCO's officers were granted 820,317 restricted share units which have a vesting percentage between 0% and 200% depending on EXCO's total shareholder return ("TSR") 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.
	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, 2014 and 2013 is as follows:
			Target Price Awards						TSRs
			Shares			Weighted average grant date fair value per share			Shares			Weighted average grant date fair value per share
	Non-vested shares outstanding at December 31, 2012		—			$	—		—			$	—
	Granted		736,000			6.36			—			—
	Vested		—			—			—			—
	Forfeited		(261,400	)		6.36			—			—
	Non-vested shares outstanding at December 31, 2013		474,600			$	6.36		—			$	—
	Granted		—			—			820,317			7.33
	Vested		—			—			—			—
	Forfeited		(73,200	)		6.36			(104,167	)		7.33
	Non-vested shares outstanding at December 31, 2014		401,400			$	6.36		716,150			$	7.33

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013 and 2012, consisted of the following:
		Year ended December 31,
	(in thousands)	2014			2013			2012
	Current:
	Federal	$	—		$	—		$	—
	State	—			—			—
	Total current income tax (benefit)	$	—		$	—		$	—
	Deferred:
	Federal	$	45,797		$	25,626		$	(485,543	)
	State	18,960			3,239			(59,406		)
	Valuation allowance	(64,757		)	(28,865		)	544,949
	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)	31-Dec-14			31-Dec-13
	Current deferred tax assets (liabilities):
	Derivative financial instruments	$	(38,519	)	$	—
	Other	2,584			5,332
	Valuation allowance	—			(5,332		)
	Net current deferred tax assets (liabilities)	(35,935		)	—
	Non-current deferred tax assets:
	Net operating loss and AMT credits carryforwards	$	781,899		$	737,399
	Capital loss carryforwards	40,356			—
	Share-based compensation	14,856			16,060
	Oil and natural gas properties, gathering assets, and equipment	—			47,491
	Goodwill	5,419			9,812
	Derivative financial instruments	—			2,102
	Investment in partnerships	72,988			73,328
	Other	84			85
	Total non-current deferred tax assets	915,602			886,277
	Valuation allowance	(826,852		)	(886,277		)
	Total non-current deferred tax assets	88,750			—
	Non-current deferred tax liabilities:
	Oil and natural gas properties, gathering assets, and equipment	$	(51,961	)	$	—
	Derivative financial instruments	(854		)	—
	Total non-current deferred tax liabilities	(52,815		)	—
	Net non-current deferred tax assets (liabilities)	$	35,935		$	—
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, 2014, 2013 and 2012 is presented in the following table:
		Year Ended December 31,
	(in thousands)	2014			2013			2012
	Federal income taxes (benefit) provision at statutory rate of 35%	$	42,234		$	7,772		$	(487,649	)
	Increases (reductions) resulting from:
	Goodwill	—			16,382			—
	Adjustments to the valuation allowance	(64,757		)	(28,865		)	544,949
	Non-deductible compensation	3,409			1,328			1,893
	State taxes net of federal benefit	3,464			3,239			(59,406		)
	State tax rate change	15,496			—			—
	Other	154			144			213
	Total income tax provision	$	—		$	—		$	—

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Schedule Of Related Party Transactions	For the years ended December 31, 2014, 2013 and 2012 these transactions included the following:
			Year Ended December 31,
	(in thousands)		2014		2013		2012
	Advances to OPCO		$	—	$	28,378	$	76,729
	Amounts received from OPCO		53,002		43,632		52,206
	As of December 31, 2014 and 2013, the amounts owed under the service agreements were as follows:
	(in thousands)		31-Dec-14		31-Dec-13
	Amounts due to EXCO (1)		$	2,799	$	2,283
	Amounts due from EXCO (1)		—		—
	-1	OPCO is the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis, which are recorded in "Other current assets" on our 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 Consolidated Balance Sheets.

Condensed_Consolidating_Financ1

Condensed Consolidating Financial Statements (Tables)	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule Of Condensed Consolidating Balance Sheet	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
	Gathering, office, field and other assets, net	1,269			23,375			—			—			24,644
	Investments in and advances to affiliates, net	1,746,931			—			—			(1,746,931		)	—
	Deferred financing costs, net	30,636			—			—			—			30,636
	Derivative financial instruments	2,138			—			—			—			2,138
	Goodwill	13,293			149,862			—			—			163,155
	Deferred income taxes	35,935			—			—			—			35,935
	Total assets	$	2,032,251		$	2,015,591		$	55,985		$	(1,746,931	)	$	2,356,896
	Liabilities and shareholders' equity
	Current liabilities	$	75,441		$	289,930		$	—		$	—		$	365,371
	Long-term debt	1,446,535			—			—			—			1,446,535
	Deferred income taxes	—			—			—			—			—
	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	$	2,032,251		$	2,015,591		$	55,985		$	(1,746,931	)	$	2,356,896
	EXCO RESOURCES, INC.
	CONDENSED CONSOLIDATING BALANCE SHEET
	December 31, 2013
	(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	Assets
	Current assets:
	Cash and cash equivalents	$	81,840		$	(35,892	)	$	4,535		$	—		$	50,483
	Restricted cash	—			20,570			—			—			20,570
	Other current assets	22,533			206,708			5,560			—			234,801
	Total current assets	104,373			191,386			10,095			—			305,854
	Equity investments	—			—			57,562			—			57,562
	Oil and natural gas properties (full cost accounting method):
	Unproved oil and natural gas properties and development costs not being amortized	6,758			415,290			3,259			—			425,307
	Proved developed and undeveloped oil and natural gas properties	337,972			3,097,335			118,903			—			3,554,210
	Accumulated depletion	(330,086		)	(1,840,332		)	(13,046		)	—			(2,183,464		)
	Oil and natural gas properties, net	14,644			1,672,293			109,116			—			1,796,053
	Gathering, office, field and other assets, net	3,481			24,639			22,248			—			50,368
	Investments in and advances to affiliates, net	1,834,197			—			—			(1,834,197		)	—
	Deferred financing costs, net	27,771			—			1,036			—			28,807
	Derivative financial instruments	6,829			—			—			—			6,829
	Goodwill	13,293			149,862			—			—			163,155
	Total assets	$	2,004,588		$	2,038,180		$	200,057		$	(1,834,197	)	$	2,408,628
	Liabilities and shareholders' equity
	Current liabilities	$	76,174		$	264,485		$	8,511		$	—		$	349,170
	Long-term debt	1,770,427			—			88,485			—			1,858,912
	Deferred income taxes	—			—			—			—			—
	Other long-term liabilities	10,082			33,831			8,728			—			52,641
	Payable to parent	—			2,230,108			35,777			(2,265,885		)	—
	Total shareholders' equity	147,905			(490,244		)	58,556			431,688			147,905
	Total liabilities and shareholders' equity	$	2,004,588		$	2,038,180		$	200,057		$	(1,834,197	)	$	2,408,628
Schedule Of Condensed Consolidating Statement Of Operations	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 OPERATIONS
	For the year ended December 31, 2012
	(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	Revenues:
	Oil and natural gas	$	78,649		$	467,960		$	—		$	—		$	546,609
	Costs and expenses:
	Oil and natural gas production	19,820			84,790			—			—			104,610
	Gathering and transportation	—			102,875			—			—			102,875
	Depletion, depreciation and amortization	7,767			295,389			—			—			303,156
	Impairment of oil and natural gas properties	—			1,346,749			—			—			1,346,749
	Accretion of discount on asset retirement obligations	526			3,361			—			—			3,887
General and administrative	14,394			69,424			—			—			83,818
Other operating items	(194		)	17,223			—			—			17,029
Total costs and expenses	42,313			1,919,811			—			—			1,962,124
Operating income (loss)	36,336			(1,451,851		)	—			—			(1,415,515		)
Other income:
Interest expense, net	(73,489		)	(3		)	—			—			(73,492		)
Gain on derivative financial instruments	62,812			3,321			—			—			66,133
Other income	238			731			—			—			969
Equity income	—			—			28,620			—			28,620
Net loss from consolidated subsidiaries	(1,419,182		)	—			—			1,419,182			—
Total other income (expense)	(1,429,621		)	4,049			28,620			1,419,182			22,230
Income (loss) before income taxes	(1,393,285		)	(1,447,802		)	28,620			1,419,182			(1,393,285		)
Income tax expense	—			—			—			—			—
Net income (loss)	$	(1,393,285	)	$	(1,447,802	)	$	28,620		$	1,419,182		$	(1,393,285	)
Schedule Of Condensed Consolidating Statement Of Cash Flows	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		)
	Restricted cash	—			(3,400		)	—			—			(3,400		)
	Equity method investments	—			1,749			—			—			1,749
	Proceeds from disposition of property and equipment	99,612			95,594			(7,551		)	—			187,655
	Distributions received from Compass	5,856			—			—			(5,856		)	—
	Net changes in advances to joint ventures	—			(5,026		)	—			—			(5,026		)
	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	(10,188		)	—			(102		)	—			(10,290		)
	Payments of common shares repurchased	(136		)	—			—			—			(136		)
	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 and property acquisitions	(15,767		)	(1,242,667		)	(38,818		)	—			(1,297,252		)
	Restricted cash	—			49,515			—			—			49,515
	Equity method investments	—			236,289			—			—			236,289
	Proceeds from disposition of property and equipment	244,500			505,128			—			—			749,628
	Distributions from Compass	3,825			—			—			(3,825		)	—
	Net changes in advances to joint ventures	—			10,645			—			—			10,645
	Advances/investments with affiliates	(59,575		)	59,575			—			—			—
	Other	(1,303		)	—			—			—			(1,303		)
	Net cash provided by (used in) investing activities	171,680			(381,515		)	(38,818		)	(3,825		)	(252,478		)
	Financing Activities:
	Borrowings under credit agreements	967,766			—			36,757			—			1,004,523
	Repayments under 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
	EXCO RESOURCES, INC.
	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	For the year ended December 31, 2012
	(in thousands)	Resources			Guarantor Subsidiaries			Non-guarantor subsidiaries			Eliminations			Consolidated
	Operating Activities:
	Net cash provided by operating activities	$	182,143		$	332,643		$	—		$	—		$	514,786
	Investing Activities:
	Additions to oil and natural gas properties, gathering assets and equipment	(77,006		)	(459,917		)	—			—			(536,923		)
	Restricted cash	—			85,840			—			—			85,840
Equity method investments	—			(14,907		)	—			—			(14,907		)
Proceeds from disposition of property and equipment	15,161			22,884			—			—			38,045
Net changes in advances to joint ventures	—			851			—			—			851
Advances/investments with affiliates	(59,126		)	59,126			—			—			—
Net cash used in investing activities	(120,971		)	(306,123		)	—			—			(427,094		)
Financing Activities:
Borrowings under the credit agreements	53,000			—			—			—			53,000
Repayments under the credit agreements	(93,000		)	—			—			—			(93,000		)
Proceeds from issuance of common shares, net	1,968			—			—			—			1,968
Payment of common share dividends	(34,358		)	—			—			—			(34,358		)
Deferred financing costs and other	(1,655		)	—			—			—			(1,655		)
Net cash used in financing activities	(74,045		)	—			—			—			(74,045		)
Net increase (decrease) in cash	(12,873		)	26,520			—			—			13,647
Cash at beginning of period	78,664			(46,667		)	—			—			31,997
Cash at end of period	$	65,791		$	(20,147	)	$	—		$	—		$	45,644

Quarterly_Financial_Data_unaud1

Quarterly Financial Data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Information	The following are summarized quarterly financial data for the years ended December 31, 2014 and 2013:
			Quarter
	(in thousands, except per share amounts)		1st			2nd		3rd			4th
	2014
	Oil and natural gas revenues		$	198,472		$	182,966	$	151,042		$	127,789
	Operating income (loss)		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		$	0.3
	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		$	0.3
	Weighted average shares		260,716			271,226		272,066			271,053
	2013
	Oil and natural gas revenues		$	138,223		$	150,332	$	165,314		$	180,440
	Operating income (loss) (1)		209,075			33,883		15,594			(79,331		)
	Net income (loss) (2) (3)		$	158,120		$	85,598	$	(98,651	)	$	(122,863	)
	Basic earnings (loss) per share:
	Net income (loss)		$	0.74		$	0.4	$	(0.46	)	$	(0.57	)
	Weighted average shares		214,784			214,788		215,056			215,410
	Diluted earnings (loss) per share:
	Net income (loss)		$	0.74		$	0.4	$	(0.46	)	$	(0.57	)
	Weighted average shares		214,861			216,023		215,056			215,410
	-1	Operating income (loss) for the first quarter and the fourth quarter of 2013 includes $10.7 million and $97.8 million, respectively, of impairments of oil and natural gas properties. See "Note 2. Summary of significant accounting policies" for further discussion.
	-2	Net income (loss) for the third quarter of 2013 includes a $91.5 million impairment to our investment in TGGT as a result of the carrying value exceeding the fair value. The impairment was reduced by $4.7 million in the fourth quarter of 2013 to $86.8 million as a result of final closing adjustments, fees and transaction expenses related to the sale of our equity investment in TGGT. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion.
	-3	Net income (loss) for the first quarter of 2013 includes a gain of $187.0 million from our contribution of oil and natural gas properties to Compass. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion.

Supplemental_Information_Relat1

Supplemental Information Relating To Oil And Natural Gas Producing Activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
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
	2014:00:00
	Proved property acquisition costs		$	10,562
	Unproved property acquisition costs		—
	Total property acquisition costs		10,562
	Development		354,199
	Exploration costs (1)		5,906
	Lease acquisitions and other		9,681
	Capitalized asset retirement costs		576
	Depletion per Boe		$	11.42
	Depletion per Mcfe		$	1.9
	2013:00:00
	Proved property acquisition costs		$	754,370
	Unproved property acquisition costs		232,020
	Total property acquisition costs (2)		986,390
	Development		231,447
	Exploration costs (3)		38,579
	Lease acquisitions and other		14,835
	Capitalized asset retirement costs		514
	Depletion per Boe		$	8.82
	Depletion per Mcfe		$	1.47
	2012:00:00
	Proved property acquisition costs		$	—
	Unproved property acquisition costs		3,349
	Total property acquisition costs		3,349
	Development		346,017
	Exploration costs (4)		57,325
	Lease acquisitions and other (5)		44,546
	Capitalized asset retirement costs		971
	Depletion per Boe		$	9.11
	Depletion per Mcfe		$	1.52
	-1	Exploration costs in 2014 include $5.9 million in the Bossier shale in North Louisiana.
	-2	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.
	-3	Exploration costs in 2013 include $29.2 million in the Eagle Ford shale and $9.4 million in the Marcellus shale.
	-4	Exploration costs in 2012 include $40.1 million in the Haynesville shale $17.2 million in the Marcellus shale.
	-5	Lease acquisition costs in 2012 are net of acreage reimbursements from BG Group totaling $2.1 million.
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			Natural Gas Liquids (Mbbls)			Mmcfe (11)
			(Mbbls)			Gas
						(Mmcf)
	December 31, 2011		6,354			1,291,464			—			1,329,588
	Purchase of reserves in place		—			—			—			—
	Discoveries and extensions (1)		492			96,615			424			102,111
	Revisions of previous estimates:
	Changes in price		(110	)		(466,238	)		—			(466,898	)
	Other factors (2)		(463	)		199,784			6,724			237,350
	Sales of reserves in place		—			(2,837	)		—			(2,837	)
	Production		(703	)		(182,656	)		(509	)		(189,928	)
	December 31, 2012		5,570			936,132			6,639			1,009,386
	Purchase of reserves in place (3)		16,022			290,933			2,201			400,271
	Discoveries and extensions (4)		5,960			46,834			513			85,672
	Revisions of previous estimates:
	Changes in price		457			272,614			686			279,472
	Other factors (5)		(3,219	)		(106,695	)		(741	)		(130,455	)
	Sales of reserves in place (6)		(8,224	)		(270,018	)		(6,472	)		(358,194	)
	Production		(1,188	)		(153,321	)		(243	)		(161,907	)
	31-Dec-13		15,378			1,016,479			2,583			1,124,245
	Purchase of reserves in place (7)		—			7,316			—			7,316
	Discoveries and extensions (8)		4,164			69,902			107			95,528
	Revisions of previous estimates:
	Changes in price		45			167,302			127			168,334
	Other factors (9)		1,737			120,850			(8	)		131,224
	Sales of reserves in place (10)		(1,401	)		(105,841	)		(2,144	)		(127,111	)
	Production		(2,236	)		(120,980	)		(224	)		(135,740	)
	31-Dec-14		17,687			1,155,028			441			1,263,796
	Estimated Quantities of Proved Developed and Proved Undeveloped Reserves
			Oil			Natural			Natural Gas Liquids (Mbbls)			Mmcfe
			(Mbbls)			Gas
						(Mmcf)
	Proved developed:
	December 31, 2014		14,429			502,314			387			591,210
	December 31, 2013		11,274			657,116			2,088			737,291
	December 31, 2012		4,371			917,326			4,784			972,256
	Proved undeveloped:
	December 31, 2014		3,258			652,714			54			672,586
	December 31, 2013		4,104			359,363			495			386,954
	December 31, 2012		1,199			18,806			1,855			37,130
	-1	New discoveries and extensions in 2012 include 25,626 Mmcfe in East Texas/North Louisiana, primarily in the Haynesville shale, 59,455 Mmcfe in the Marcellus shale and 17,027 Mmcfe in the Permian Basin.
	-2	Total revisions due to Other factors in 2012 include approximately 8,736 Mmcfe of Proved Undeveloped Reserves that were reclassified to unproved reserves as a result of a slower development schedule due to depressed natural gas prices, which extended their scheduled development beyond a five-year development horizon. The change also includes a positive revision of 246,451 Mmcfe resulting from unproved performance and cost reductions.
	-3	Purchases of reserves in place include 115,718 Mmcfe in the Eagle Ford shale, 259,991 Mmcfe in the Haynesville shale, and 24,558 Mmcfe for our proportionate share of Compass's acquisition of shallow Cotton Valley assets in East Texas/North Louisiana.
	-4	New discoveries and extensions in 2013 include 36,501 Mmcfe in the Eagle Ford shale, 33,591 Mmcfe in the Marcellus shale, 10,211 Mmcfe in the Haynesville shale, 3,881 Mmcfe for conventional properties held by Compass in the Permian Basin, and 1,486 Mmcfe for shale properties in the Permian Basin.
	-5	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.
	-6	Sales of reserves in place in 2013 include 327,608 Mmcfe as a result of our contribution of properties to Compass and 30,582 Mmcfe from the sale of undeveloped properties in the Eagle Ford in connection with the Participation Agreement.
	-7	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.
	-8	New discoveries and extensions in 2014 included 48,698 Mmcfe in the Haynesville shale, 26,148 Mmcfe in the Eagle Ford Shale and 19,664 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.
	-9	Total revisions due to Other factors include upward revisions of approximately 67,095 Mmcfe in the Shelby area, approximately 45,878 Mmcfe in the Appalachia region, and approximately 5,836 Mmcfe in the Holly area. The upward revisions were primarily due to improved well performance resulting from enhanced well designs and completion techniques.
	-10	Sales of reserves in place in 2014 consist primarily of the sale of our entire interest in Compass.
	-11	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, natural gas and NGL 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, 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
	Year ended December 31, 2012:
	Future cash inflows		$	3,187,480
	Future production costs		1,824,702
	Future development costs		266,726
	Future income taxes		—
	Future net cash flows		1,096,052
	Discount of future net cash flows at 10% per annum		399,905
	Standardized measure of discounted future net cash flows		$	696,147
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, 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
	Year ended December 31, 2012:
	Sales and transfers of oil and natural gas produced		$	(339,125	)
	Net changes in prices and production costs		(1,258,493		)
	Extensions and discoveries, net of future development and production costs		90,633
	Development costs during the period		204,929
	Changes in estimated future development costs		404,414
	Revisions of previous quantity estimates		(336,142		)
	Sales of reserves in place		(3,604		)
	Purchase of reserves in place		—
	Accretion of discount before income taxes		165,755
	Changes in timing and other		94,129
	Net change in income taxes		247,189
	Net change		$	(730,315	)
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				2014				2013			2012		2011 and
																prior
	Property acquisition costs		$	228,553			$	9,737			$	71,524		$	3,038	$	144,254
	Exploration and development		16,366				10,797				73			524		4,972
	Capitalized interest		31,106				11,871				8,737			6,796		3,702
	Total		$	276,025			$	32,405			$	80,334		$	10,358	$	152,928

Organization_And_Basis_Of_Pres1

Organization And Basis Of Presentation (Narrative) (Details)	12 Months Ended
	Dec. 31, 2014
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_Account3

Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)	3 Months Ended		12 Months Ended
	Dec. 31, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
			revenue_reported_base
			agreement
Summary Of Significant Accounting Policies [Line Items]
Unproved oil and natural gas properties and development cost	$425,307,000		$276,025,000	$425,307,000
Impairment of unproved costs to proved properties			0	1,000,000	60,800,000
Full cost ceiling limitation discount rate			10.00%
Reference prices per mmbtu of natural gas			4.35	3.67	2.76
Reference prices per bbl of oil			94.99	96.78	94.71
Reference prices per Barrel of Natural Gas Liquids			33.03	39.92	46.57
Impairment of oil and natural gas properties	97,800,000	10,700,000	0	108,546,000	1,346,749,000
Percentage of Fair Value in Excess of Carrying Amount			18.00%
Number of Agreements to Sell Oil and Gas			2
Number of Revenue Reporting Bases			2
Gathering and transportation			101,574,000	100,645,000	102,875,000
Personnel costs capitalized to full cost pool	18,200,000		15,800,000	18,200,000	22,500,000
Capitalized share-based compensation			5,498,000	7,288,000	7,513,000
Overhead charges billed to working interest owners			13,500,000	10,500,000	20,500,000
Overhead charges classified as oil and natural gas production costs			6,400,000	5,800,000	10,300,000
Reduced general and administrative expenses			$24,700,000	$26,800,000	$25,200,000
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	14.00%		31.00%	14.00%
B G Energy Merchants L L C [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of consolidated revenues	48.00%		34.00%	48.00%	36.00%
Compass [Member]
Summary Of Significant Accounting Policies [Line Items]
Ownership percentage in joint venture	25.50%		25.50%	25.50%

Summary_Of_Significant_Account4

Summary Of Significant Accounting Policies (Reconciliation Of Asset Retirement Obligations) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of period	$42,954		$61,864		$58,088
Liabilities incurred during the period	576		514		971
Revisions in estimated assumptions	0		1,268		0
Liabilities settled during the period	-33		-187		-338
Adjustment to liability due to acquisitions	107		5,566		0
Adjustment to liability due to divestitures (1)	-9,539	[1]	-28,585	[1]	-744	[1]
Accretion of discount	2,690		2,514		3,887
Asset retirement obligations at end of period	36,755		42,954		61,864
Less current portion	1,769		191		1,200
Long-term portion	34,986		42,763		60,664
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.

Divestitures_Acquisitions_And_1

Divestitures, Acquisitions And Other Significant Events (Details) (USD $)	0 Months Ended	12 Months Ended			3 Months Ended	1 Months Ended
	Oct. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Business Acquisition [Line Items]
Decrease to capitalized costs	$87,400,000
Gain on Disposition of Property Plant Equipment		17,000	185,163,000	-1,303,000
Payments to Acquire Oil and Gas Property and Equipment		10,790,000	976,714,000	2,748,000
Oil and Gas Property, Full Cost Method, Gross		3,852,073,000	3,554,210,000
Asset Retirement Obligation		36,755,000	42,954,000	61,864,000		61,864,000	58,088,000
Equity Method Investment, Other than Temporary Impairment			86,800,000
Compass [Member]
Business Acquisition [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	118,800,000		574,800,000
Ownership percentage in joint venture		25.50%	25.50%
Net Assets	31,400,000
HGI's economic interest in Compass			74.50%
Gain on Disposition of Property Plant Equipment			186,400,000		187,000,000
Reduction in goodwill			55,100,000
Payments to Acquire Oil and Gas Property and Equipment			130,700,000
Appalachia Transaction [Member]
Business Acquisition [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment						14,300,000
Acreage transaction [Member]
Business Acquisition [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment		68,200,000	37,900,000
Sale of undivided interest percentage			50.00%
Haynesville [Member]
Business Acquisition [Line Items]
Acquisition purchase price			281,101,000
Wells operated by EXCO			170
Net acres acquired on wells operated by EXCO			5,500
Wells operated by Chesapeake			11
Net acres acquired on Chesapeake operated wells			4,000
Identified drilling locations			55
Percent of assets subject to preferential right			50.00%
Oil and Gas Property, Full Cost Method, Gross			285,200,000
Asset Retirement Obligation			610,000
Eagle Ford [Member]
Business Acquisition [Line Items]
Acquisition purchase price			661,845,000
Wells operated by Chesapeake			120
Net acres acquired on Chesapeake operated wells			53,500
Oil and Gas Property, Full Cost Method, Gross			665,500,000
Asset Retirement Obligation			3,060,000
KKR [Member]
Business Acquisition [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			130,900,000
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			13,400,000
TGGT [Member]
Business Acquisition [Line Items]
Equity Method Investment, Net Sales Proceeds			240,200,000
Combined EXCO and BG Group's 100% interest [Member]
Business Acquisition [Line Items]
Minimum volume commitment per day of natural gas production			600,000
Amount per mmbtu multiplied by shortfall to the minimum volume commitment			0.4
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	$83,200,000	$0	$88,485,000

Divestitures_Acquisitions_And_2

Divestitures, Acquisitions And Other Significant Events (Purchase Price Allocation) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Business Acquisition [Line Items]
Unproved oil and natural gas properties	$276,025	$425,307
Accounts Payable and Accrued Liabilities, Current	-110,211	-109,217
Revenues and royalties payable	-152,651	-154,862
Asset Retirement Obligation	-36,755	-42,954	-61,864	-58,088
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

Divestitures_Acquisitions_And_3

Divestitures, Acquisitions And Other Significant Events (Pro Forma Information) (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Oil and natural gas revenues	$784,628		$715,286
Net income (loss) (1)	$38,663	[1]	($1,398,169)	[1]
Basic earnings (loss) per share	$0.18		($6.52)
Diluted earnings (loss) per share	$0.17		($6.52)
[1]	Net loss for the year ended December 31, 2012 was primarily due to the impairment of our oil and natural gas properties due to the significant decline in natural gas prices.

Derivative_Financial_Instrumen2

Derivative Financial Instruments (Narrative) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Percentage of derivative instruments to equivalent production	69.00%	57.00%
2015 [Member] | Natural Gas [Member]
Derivative [Line Items]
Average forward NYMEX prices	3.01
2015 [Member] | NYMEX LLS [Member] | Oil [Member]
Derivative [Line Items]
Average forward NYMEX prices	58.51
2015 [Member] | NYMEX WTI [Member] | Oil [Member]
Derivative [Line Items]
Average forward NYMEX prices	56.26
2016 [Member] | Natural Gas [Member]
Derivative [Line Items]
Average forward NYMEX prices	3.46
Swap [Member] | Oil [Member]
Derivative [Line Items]
Investment Contract Volume		2,192,000
Swap [Member] | Natural Gas [Member]
Derivative [Line Items]
Natural gas volume		112,348,000
Swap [Member] | 2015 [Member] | Oil [Member]
Derivative [Line Items]
Investment Contract Volume	1,095,000
Swap [Member] | 2015 [Member] | Natural Gas [Member]
Derivative [Line Items]
Natural gas volume	42,888,000
Basis Swap [Member] | Oil [Member]
Derivative [Line Items]
Investment Contract Volume		274,000
Basis Swap [Member] | 2015 [Member] | Oil [Member]
Derivative [Line Items]
Investment Contract Volume	91,000
Call Option [Member] | Oil [Member]
Derivative [Line Items]
Investment Contract Volume		730,000
Call Option [Member] | Natural Gas [Member]
Derivative [Line Items]
Natural gas volume		40,150,000
Call Option [Member] | 2015 [Member] | Oil [Member]
Derivative [Line Items]
Investment Contract Volume	365,000
Call Option [Member] | 2015 [Member] | Natural Gas [Member]
Derivative [Line Items]
Natural gas volume	20,075,000

Derivative_Financial_Instrumen3

Derivative Financial Instruments (Fair Value Of Derivative Financial Instruments) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Derivative financial instruments - Current assets	$97,278	$8,226
Derivative financial instruments - Long-term assets	2,138	6,829
Derivative financial instruments - Current liabilities	-892	-11,919
Derivative financial instruments - Long-term liabilities	0	-9,671
Net derivative financial instruments	$98,524	($6,535)

Derivative_Financial_Instrumen4

Derivative Financial Instruments (Effect Of Derivative Financial Instruments) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Gain (Loss) on derivative financial instruments	$87,665	($320)	$66,133

Derivative_Financial_Instrumen5

Derivative Financial Instruments (Fair Value Of Oil And Natural Gas Derivative Financial Instruments) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	$98,524	($6,535)
Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	61,485
Oil [Member]
Derivatives, Fair Value [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	37,039
Swap [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu		112,348,000
Swap [Member] | Oil [Member]
Derivatives, Fair Value [Line Items]
Volume (oil)		2,192,000
Swap [Member] | 2015 [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu	42,888,000
Weighted average strike price per Mmbtu/Bbl	4.2
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	49,926
Swap [Member] | 2015 [Member] | Oil [Member]
Derivatives, Fair Value [Line Items]
Volume (oil)	1,095,000
Weighted average strike price per Mmbtu/Bbl	91.09
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	36,797
Call Option [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu		40,150,000
Call Option [Member] | Oil [Member]
Derivatives, Fair Value [Line Items]
Volume (oil)		730,000
Call Option [Member] | 2015 [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu	20,075,000
Weighted average strike price per Mmbtu/Bbl	4.29
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	-784
Call Option [Member] | 2015 [Member] | Oil [Member]
Derivatives, Fair Value [Line Items]
Volume (oil)	365,000
Weighted average strike price per Mmbtu/Bbl	100
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	-108
Three Way Collars [Member] | 2015 [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu	27,375,000
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	10,205
Three Way Collars [Member] | 2016 [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu	10,980,000
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	2,138
Basis Swap [Member] | Oil [Member]
Derivatives, Fair Value [Line Items]
Volume (oil)		274,000
Basis Swap [Member] | 2015 [Member] | Oil [Member]
Derivatives, Fair Value [Line Items]
Volume (oil)	91,000
Weighted average strike price per Mmbtu/Bbl	6.1
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	$350
Short [Member] | Call Option [Member] | Three Way Collars [Member] | 2015 [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Weighted average strike price per Mmbtu/Bbl	4.47
Short [Member] | Call Option [Member] | Three Way Collars [Member] | 2016 [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Weighted average strike price per Mmbtu/Bbl	4.8
Short [Member] | Put Option [Member] | Three Way Collars [Member] | 2015 [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Weighted average strike price per Mmbtu/Bbl	3.33
Short [Member] | Put Option [Member] | Three Way Collars [Member] | 2016 [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Weighted average strike price per Mmbtu/Bbl	3.4
Long [Member] | Put Option [Member] | Three Way Collars [Member] | 2015 [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Weighted average strike price per Mmbtu/Bbl	3.83
Long [Member] | Put Option [Member] | Three Way Collars [Member] | 2016 [Member] | Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Weighted average strike price per Mmbtu/Bbl	3.9

Fair_Value_Measurements_Narrat

Fair Value Measurements (Narrative) (Details)	Dec. 31, 2014
Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	7.50%
Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	8.50%

Fair_Value_Measurements_Summar

Fair Value Measurements (Summary Of Estimated Fair Value Of Derivative Financial Instruments) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	$98,524	($6,535)
Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	0	0
Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	98,524	-6,535
Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	$0	$0

Fair_Value_Measurements_Schedu

Fair Value Measurements (Schedule Of Estimated Fair Value Of Other Financial Instruments) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Senior Unsecured Notes due 2018 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$558,750	$714,000
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	558,750	714,000
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	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	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
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
Term loan [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure		298,500
Term loan [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure		298,500
Term loan [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure		0
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

Debt_Narrative_Details

Debt (Narrative) (Details) (USD $)	0 Months Ended	12 Months Ended			60 Months Ended	3 Months Ended				6 Months Ended	9 Months Ended	12 Months Ended	24 Months Ended		0 Months Ended	6 Months Ended
	Jan. 17, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016	Jun. 30, 2017	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2016	Feb. 06, 2015	Mar. 31, 2017	Apr. 16, 2014	Oct. 31, 2014
Debt Instrument [Line Items]
Proceeds from issuance of common stock	$272,900,000	$271,773,000	$1,712,000	$1,968,000
Common stock repurchased to date		136,000			7,615,000
Shares paid for tax withholding for share based compensation		38,821
Adjustments related to tax withholding for share-based compensation		100,000
EXCO Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Decrease in interest rate from reduction of debt from asset sales		1.00%			1.00%
Amount of dividend restriction		75,000,000
Percentage of Revolving Commitment		10.00%
Current ratio, numerator		1
Current ratio, denominator		1
Maximum Leverage Ratio		4.5
Leverage ratio, denominator		1
Stock Repurchase Program, Authorized Amount		200,000,000			200,000,000
Minimum security interest as percentage of Engineered Value		80.00%
Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, principal outstanding		750,000,000	750,000,000		750,000,000
Unamortized discount		5,957,000	7,293,000		5,957,000
Debt Instrument, Interest Rate, Stated Percentage		7.50%			7.50%
Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, principal outstanding		500,000,000	0		500,000,000
Debt Instrument, Interest Rate, Stated Percentage		8.50%			8.50%
Proceeds from Debt, Net of Issuance Costs		490,000,000
Debt Instrument, Issued Price, Percentage		100.00%			100.00%
Scenario, Forecast [Member] | EXCO Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Maximum Leverage Ratio						4.5	4.75	5.25	6	5.75
Leverage Ratio, multiplier to use when calculating EBITDAX											1.33
Maximum percentage of production for derivatives coverage												90.00%	85.00%	100.00%
Revolving Credit Facility [Member] | EXCO Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Outstanding indebtedness		202,492,000	763,866,000		202,492,000
Borrowing base		900,000,000			900,000,000
Unused borrowing base		690,900,000			690,900,000
Line of credit facility, maturity date		31-Jul-18
Reference rate to compute the variable rate on the debt instrument		0.20%
Line of credit facility, interest rate at period end		1.90%			1.90%
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		1.75%
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		2.75%
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		0.75%
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		1.75%
Term loan [Member] | EXCO Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Outstanding indebtedness		0	298,500,000		0												297,800,000
Unamortized discount		0	2,780,000		0
Compass [Member] | Compass Production Partners Credit Agreement [Member]
Debt Instrument [Line Items]
Outstanding indebtedness		0	88,485,000		0													83,200,000
Subsequent Event [Member] | EXCO Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Current ratio, numerator															1
Current ratio, denominator															1
Interest Coverage Ratio															2
Secured Indebtedness Ratio															2.5
Subsequent Event [Member] | Scenario, Forecast [Member] | EXCO Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Leverage Ratio, multiplier to use when calculating EBITDAX									4							2
Subsequent Event [Member] | Revolving Credit Facility [Member] | EXCO Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Borrowing base															725,000,000

Debt_Schedule_Of_LongTerm_Debt

Debt (Schedule Of Long-Term Debt) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Apr. 16, 2014	Oct. 31, 2014
In Thousands, unless otherwise specified
Debt Instrument [Line Items]
Total debt excluding Compass Production Partners	$1,446,535	$1,802,293
Total debt	1,446,535	1,890,778
Current maturities of long-term debt	0	31,866
Total debt due after one year	1,446,535	1,858,912
Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument	750,000	750,000
Unamortized discount	-5,957	-7,293
Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument	500,000	0
Revolving Credit Facility [Member] | EXCO Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Revolving credit facility under credit agreement	202,492	763,866
Term loan [Member] | EXCO Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Revolving credit facility under credit agreement	0	298,500	297,800
Unamortized discount	0	-2,780
Compass [Member] | Compass Production Partners Credit Agreement [Member]
Debt Instrument [Line Items]
Revolving credit facility under credit agreement	$0	$88,485		$83,200

Commitments_And_Contingencies_1

Commitments And Contingencies (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commitments and Contingencies Disclosure [Abstract]
Rental expenses	$5.10	$5.90	$6.80

Commitments_And_Contingencies_2

Commitments And Contingencies (Schedule Of Future Minimum Rental Payments Under Operation Leases) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Long-term Purchase Commitment [Line Items]
2015	$181,475
2016	154,443
2017	142,150
2018	135,444
2019	94,514
Thereafter	106,771
Total	814,797
Gathering and Firm Transportation Services [Member]
Long-term Purchase Commitment [Line Items]
2015	136,040
2016	133,429
2017	132,860
2018	129,140
2019	89,060
Thereafter	101,618
Total	722,147
Other Fixed Commitments [Member]
Long-term Purchase Commitment [Line Items]
2015	17,332
2016	13,253
2017	5,443
2018	3,210
2019	2,403
Thereafter	3,530
Total	45,171
Drilling Contracts [Member]
Long-term Purchase Commitment [Line Items]
2015	22,191
2016	2,538
2017	0
2018	0
2019	0
Thereafter	0
Total	24,729
Operating Leases And Other [Member]
Long-term Purchase Commitment [Line Items]
2015	5,912
2016	5,223
2017	3,847
2018	3,094
2019	3,051
Thereafter	1,623
Total	$22,750

Commitments_And_Contingencies_3

Commitments And Contingencies (Schedule of Firm Transportation Services and Gathering Services) (Details)	Dec. 31, 2014
	Mcf
Firm Transportation Services [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
2015	293,000,000
2016	272,000,000
2017	269,000,000
2018	269,000,000
2019	269,000,000
Thereafter	299,000,000
Total	1,671,000,000
Gathering Services [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
2015	110,000,000
2016	110,000,000
2017	110,000,000
2018	100,000,000
2019	0
Thereafter	0
Total	430,000,000

Employee_Benefit_Plans_Details

Employee Benefit Plans (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
General Discussion of Pension and Other Postretirement Benefits [Abstract]
Matched employee contribution in percentage	100.00%
Contributions by employer	$7.10	$8.80	$9.40

Earnings_Per_Share_Details

Earnings Per Share (Details) (USD $)	3 Months Ended												12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net income (loss)	$81,413	$41,569	$2,293	($4,606)	($122,863)	[1],[2]	($98,651)	[1],[2]	$85,598	[1],[2]	$158,120	[1],[2]	$120,669	$22,204	($1,393,285)
Weighted average common shares outstanding	271,053	270,631	270,492	260,716	215,410		215,056		214,788		214,784		268,258	215,011	214,321
Net income (loss) per basic common share	$0.30	$0.15	$0.01	($0.02)	($0.57)		($0.46)		$0.40		$0.74		$0.45	$0.10	($6.50)
Weighted average common and common equivalent shares outstanding	271,053	272,066	271,226	260,716	215,410		215,056		216,023		214,861		268,376	230,912	214,321
Net income (loss) per diluted common share	$0.30	$0.15	$0.01	($0.02)	($0.57)		($0.46)		$0.40		$0.74		$0.45	$0.10	($6.50)
Stock Options [Member]
Dilutive effect of stock equivalents													0	0	0
Restricted Stock [Member]
Dilutive effect of stock equivalents													118	420	0
Subscription Rights (Member)
Dilutive effect of stock equivalents													0	15,481	0
[1]	Net income (loss) for the third quarter of 2013 includes a $91.5 million impairment to our investment in TGGT as a result of the carrying value exceeding the fair value. The impairment was reduced by $4.7 million in the fourth quarter of 2013 to $86.8 million as a result of final closing adjustments, fees and transaction expenses related to the sale of our equity investment in TGGT. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion.
[2]	Net income (loss) for the first quarter of 2013 includes a gain of $187.0 million from our contribution of oil and natural gas properties to Compass. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion.

Earnings_Per_Share_Details_Tex

Earnings Per Share (Details Textual)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share [Abstract]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	14,316,409	55,524,191	17,242,306

Stock_Options_And_Awards_Narra

Stock Options And Awards (Narrative) (Details) (USD $)	12 Months Ended			19 Months Ended	20 Months Ended	69 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Jun. 11, 2013	Oct. 05, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized for issuance	45,500,000			45,500,000
Shares available for grant	19,763,916	21,118,292		19,763,916
Total share-based compensation to be recognized on unvested awards	$20.40			$20.40
Total tax benefit	0	0	0
Weighted average remaining life, years	3 years 8 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	$3.96
Total intrinsic value of stock options exercised	0	0.2	0.1
Shares of common stock granted	1,339,782	556,700	926,900
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
Total share-based compensation to be recognized on unvested awards	3.1			3.1
Total share-based compensation to be recognized, weighted average period (years)	1 year 8 months
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation current granted counts				1.74	2.1	1.17
Total share-based compensation to be recognized on unvested awards	$17.30			$17.30
Total share-based compensation to be recognized, weighted average period (years)	2 years 2 months
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
Market-based restricted stock awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Vesting Period	2 years
Shares of common stock granted	736,000
$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	368,000
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	368,000
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]
Shares of common stock granted	820,317
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%

Stock_Options_And_Awards_Recon

Stock Options And Awards (Reconciliation Of Share-Based Compensation Expense) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation [Abstract]
General and administrative expense	$4,962	$10,748	$8,926
Share-based compensation capitalized	5,498	7,288	7,513
Total share-based compensation	$10,460	$18,036	$16,439

Stock_Options_And_Awards_Stock

Stock Options And Awards (Stock Option Activity) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Stock options, Options outstanding	11,711,743		14,015,795	15,670,168
Stock options, Granted	141,525	2,886,500	146,500
Stock options, Forfeitures	-1,700,250	-4,969,877	-1,543,933
Stock options, Exercised	-2,500	-220,675	-256,940
Stock options, Options outstanding	10,150,518	11,711,743		15,670,168
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	$12.69		$13.20	$13.44
Weighted average exercise price per share, Granted	$5.24	$7.48	$8
Weighted average exercise price per share, Forfeitures	$12.71	$11.32	$16.12
Weighted average exercise price per share, Exercised	$5.22	$7.66	$7.66
Weighted average exercise price per share, Options outstanding	$12.58	$12.69		$13.44
Weighted average remaining terms, Options outstanding (in years)	3 years 8 months
Aggregate intrinsic value, Options outstanding	$0
Stock options, Options exercisable	9,181,306
Weighted average exercise price per share, Options exercisable	$13.15
Weighted average remaining terms, Options exercisable (in years)	3 years 2 months
Aggregate intrinsic value, Options exercisable	$0

Stock_Options_And_Awards_Fair_

Stock Options And Awards (Fair Value Option Assumptions) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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%	0.56%
Risk-free rate of return, maximum	2.61%	2.49%	1.64%
Volatility, minimum	59.46%	49.47%	57.34%
Volatility, maximum	59.61%	59.86%	60.24%
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life		3 years 9 months 18 days	3 years 9 months 18 days
Dividend yield	3.36%	2.27%	0.52%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life		7 years 6 months	7 years 6 months
Dividend yield	4.34%	3.87%	1.92%

Stock_Options_And_Awards_Restr

Stock Options And Awards (Restricted Stock Activity) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2010
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	1,928,314		2,806,365	2,562,409
Shares, Granted	1,339,782	556,700	926,900
Shares, Vested	-1,109,866	-832,706	-370,448
Shares, Forfeited	-280,301	-602,045	-312,496
Non-vested shares outstanding at end of period	1,877,929	1,928,314		2,562,409
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	$9.26		$10.16	$11.72
Granted	$5.20	$7.15	$7.57
Vested	$9.79	$10.47	$12.89
Forfeited	$6.89	$9.84	$11.89
Weighted average grant date fair value per share at end of period	$6.40	$9.26		$11.72
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]
Shares, Granted	736,000
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	474,600	0
Shares, Granted	0	736,000
Shares, Vested	0	0
Shares, Forfeited	-73,200	-261,400
Non-vested shares outstanding at end of period	401,400	474,600
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	$0
Granted	$0	$6.36
Vested	$0	$0
Forfeited	$6.36	$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	0
Shares, Granted	820,317
Shares, Vested	0
Shares, Forfeited	-104,167
Non-vested shares outstanding at end of period	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	$0
Granted	$7.33
Vested	$0
Forfeited	$7.33
Weighted average grant date fair value per share at end of period	$7.33

Income_Taxes_Components_Of_Inc

Income Taxes (Components Of Income Tax Provision (Benefit)) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current:
Federal	$0	$0	$0
State	0	0	0
Total current income tax (benefit)	0	0	0
Deferred:
Federal	45,797,000	25,626,000	-485,543,000
State	18,960,000	3,239,000	-59,406,000
Valuation allowance	-64,757,000	-28,865,000	544,949,000
Total deferred income tax (benefit)	0	0	0
Total income tax (benefit)	0	0	0
Net operating loss carryforwards	2,000,000,000
Alternative minimum tax [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Amount	1,500,000
Capital Loss Carryforward [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Amount	$105,600,000

Income_Taxes_Significant_Compo

Income Taxes (Significant Components Of Deferred Tax Liabilities And Assets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accrued Income Taxes [Abstract]
Derivative financial instruments	($38,519)	$0
Other	2,584	5,332
Valuation allowance	0	-5,332
Net current deferred tax assets (liabilities)	-35,935	0
Net operating loss and AMT credits carryforwards	781,899	737,399
Capital loss carryforwards	40,356	0
Share-based compensation	14,856	16,060
Oil and natural gas properties, gathering assets, and equipment	0	47,491
Goodwill	5,419	9,812
Derivative financial instruments	0	2,102
Investment in partnerships	72,988	73,328
Other	84	85
Total non-current deferred tax assets	915,602	886,277
Valuation allowance	-826,852	-886,277
Total non-current deferred tax assets	88,750	0
Oil and natural gas properties, gathering assets, and equipment	-51,961	0
Derivative financial instruments	-854	0
Total non-current deferred tax liabilities	-52,815	0
Net non-current deferred tax assets (liabilities)	$35,935	$0

Income_Taxes_Reconciliation_Of

Income Taxes (Reconciliation Of Income Tax Provision (Benefit)) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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%	$42,234	$7,772	($487,649)
Goodwill	0	16,382	0
Adjustments to the valuation allowance	-64,757	-28,865	544,949
Non-deductible compensation	3,409	1,328	1,893
State taxes net of federal benefit	3,464	3,239	-59,406
State tax rate change	15,496	0	0
Other	154	144	213
Total income tax (benefit)	$0	$0	$0

Related_Party_Transactions_Nar

Related Party Transactions (Narrative) (Details) (Affiliated Entity - WL Ross [Member])	Dec. 31, 2014
Affiliated Entity - WL Ross [Member]
Related Party Transaction [Line Items]
Percent of term loan held by owner of related party	10.00%

Related_Party_Transactions_Det

Related Party Transactions (Details) (OPCO [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
OPCO [Member]
Advances to OPCO	$0		$28,378		$76,729
Amounts received from OPCO	53,002		43,632		52,206
Amounts due to EXCO (1)	2,799	[1]	2,283	[1]
Amounts due from EXCO (1)	$0	[1]	$0	[1]
[1]	OPCO is the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis, which are recorded in "Other current assets" on our 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 Consolidated Balance Sheets.

Dividends_Narrative_Details

Dividends (Narrative) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Dividends [Line Items]
Dividends, Common Stock, Cash	$41,060	$43,214	$34,358

Rights_Offering_and_other_equi1

Rights Offering and other equity transactions (Details) (USD $)	0 Months Ended	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Jan. 17, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	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	274,351,756	218,783,540
Proceeds from issuance of common stock	$272,900	$271,773	$1,712	$1,968
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, Share, New Issues	19,599,973
Stock Issued During Period, New Issues, Percentage Outstanding	18.70%
Affiliated Entity - Hamblin Watsa [Member]
Class of Stock [Line Items]
Stock Issued During Period, Share, New Issues	6,726,712
Stock Issued During Period, New Issues, Percentage Outstanding	6.40%

Condensed_Consolidating_Financ2

Condensed Consolidating Financial Statements (Schedule Of Condensed Consolidating Balance Sheet) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$46,305	$50,483	$45,644	$31,997
Restricted cash	23,970	20,570
Other current assets	260,491	234,801
Total current assets	330,766	305,854
Equity investments	55,985	57,562
Unproved oil and natural gas properties and development costs not being amortized	276,025	425,307
Proved developed and undeveloped oil and natural gas properties	3,852,073	3,554,210
Accumulated depletion	-2,414,461	-2,183,464
Oil and natural gas properties, net	1,713,637	1,796,053
Gathering, office, field and other assets, net	24,644	50,368
Investments in and advances to affiliates	0	0
Deferred financing costs, net	30,636	28,807
Derivative financial instruments	2,138	6,829
Goodwill	163,155	163,155
Deferred income taxes	35,935	0
Total assets	2,356,896	2,408,628
Liabilities and shareholders’ equity
Current liabilities	365,371	349,170
Long-term debt	1,446,535	1,858,912
Deferred income taxes	0	0
Other long-term liabilities	34,986	52,641
Payable to parent	0	0
Total shareholders' equity	510,004	147,905	149,393	1,558,332
Total liabilities and shareholders' equity	2,356,896	2,408,628
Resources [Member]
Current assets:
Cash and cash equivalents	86,837	81,840	65,791	78,664
Restricted cash	0	0
Other current assets	110,145	22,533
Total current assets	196,982	104,373
Equity investments	0	0
Unproved oil and natural gas properties and development costs not being amortized	0	6,758
Proved developed and undeveloped oil and natural gas properties	335,838	337,972
Accumulated depletion	-330,771	-330,086
Oil and natural gas properties, net	5,067	14,644
Gathering, office, field and other assets, net	1,269	3,481
Investments in and advances to affiliates	1,746,931	1,834,197
Deferred financing costs, net	30,636	27,771
Derivative financial instruments	2,138	6,829
Goodwill	13,293	13,293
Deferred income taxes	35,935
Total assets	2,032,251	2,004,588
Liabilities and shareholders’ equity
Current liabilities	75,441	76,174
Long-term debt	1,446,535	1,770,427
Deferred income taxes	0	0
Other long-term liabilities	271	10,082
Payable to parent	0	0
Total shareholders' equity	510,004	147,905
Total liabilities and shareholders' equity	2,032,251	2,004,588
Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	-40,532	-35,892	-20,147	-46,667
Restricted cash	23,970	20,570
Other current assets	150,346	206,708
Total current assets	133,784	191,386
Equity investments	0	0
Unproved oil and natural gas properties and development costs not being amortized	276,025	415,290
Proved developed and undeveloped oil and natural gas properties	3,516,235	3,097,335
Accumulated depletion	-2,083,690	-1,840,332
Oil and natural gas properties, net	1,708,570	1,672,293
Gathering, office, field and other assets, net	23,375	24,639
Investments in and advances to affiliates	0	0
Deferred financing costs, net	0	0
Derivative financial instruments	0	0
Goodwill	149,862	149,862
Deferred income taxes	0
Total assets	2,015,591	2,038,180
Liabilities and shareholders’ equity
Current liabilities	289,930	264,485
Long-term debt	0	0
Deferred income taxes	0	0
Other long-term liabilities	34,715	33,831
Payable to parent	2,058,683	2,230,108
Total shareholders' equity	-367,737	-490,244
Total liabilities and shareholders' equity	2,015,591	2,038,180
Non-Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	0	4,535	0	0
Restricted cash	0	0
Other current assets	0	5,560
Total current assets	0	10,095
Equity investments	55,985	57,562
Unproved oil and natural gas properties and development costs not being amortized	0	3,259
Proved developed and undeveloped oil and natural gas properties	0	118,903
Accumulated depletion	0	-13,046
Oil and natural gas properties, net	0	109,116
Gathering, office, field and other assets, net	0	22,248
Investments in and advances to affiliates	0	0
Deferred financing costs, net	0	1,036
Derivative financial instruments	0	0
Goodwill	0	0
Deferred income taxes	0
Total assets	55,985	200,057
Liabilities and shareholders’ equity
Current liabilities	0	8,511
Long-term debt	0	88,485
Deferred income taxes	0	0
Other long-term liabilities	0	8,728
Payable to parent	0	35,777
Total shareholders' equity	55,985	58,556
Total liabilities and shareholders' equity	55,985	200,057
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
Gathering, office, field and other assets, net	0	0
Investments in and advances to affiliates	-1,746,931	-1,834,197
Deferred financing costs, net	0	0
Derivative financial instruments	0	0
Goodwill	0	0
Deferred income taxes	0
Total assets	-1,746,931	-1,834,197
Liabilities and shareholders’ equity
Current liabilities	0	0
Long-term debt	0	0
Deferred income taxes	0	0
Other long-term liabilities	0	0
Payable to parent	-2,058,683	-2,265,885
Total shareholders' equity	311,752	431,688
Total liabilities and shareholders' equity	($1,746,931)	($1,834,197)

Condensed_Consolidating_Financ3

Condensed Consolidating Financial Statements (Schedule Of Condensed Consolidating Statement Of Operations) (Details) (USD $)	3 Months Ended												12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and natural gas	$127,789	$151,042	$182,966	$198,472	$180,440		$165,314		$150,332		$138,223		$660,269	$634,309	$546,609
Oil and natural gas production													94,326	83,248	104,610
Gathering and transportation													101,574	100,645	102,875
Depletion, depreciation and amortization													263,569	245,775	303,156
Impairment of oil and natural gas properties					97,800						10,700		0	108,546	1,346,749
Accretion of discount on asset retirement obligations													2,690	2,514	3,887
General and administrative													65,920	91,878	83,818
Other operating items													5,315	-177,518	17,029
Total costs and expenses													533,394	455,088	1,962,124
Operating income (loss)	3,341	22,799	43,312	57,423	-79,331	[1]	15,594	[1]	33,883	[1]	209,075	[1]	126,875	179,221	-1,415,515
Interest expense, net													-94,284	-102,589	-73,492
Gain (loss) on derivative financial instruments													87,665	-320	66,133
Other income (expense)													241	-828	969
Equity income (loss)													172	-53,280	28,620
Net earnings (loss) from consolidated subsidiaries													0	0	0
Total other income (expense)													-6,206	-157,017	22,230
Income (loss) before income taxes													120,669	22,204	-1,393,285
Income tax expense													0	0	0
Net income (loss)	81,413	41,569	2,293	-4,606	-122,863	[2],[3]	-98,651	[2],[3]	85,598	[2],[3]	158,120	[2],[3]	120,669	22,204	-1,393,285
Resources [Member]
Oil and natural gas													3,649	9,136	78,649
Oil and natural gas production													394	2,440	19,820
Gathering and transportation													0	0	0
Depletion, depreciation and amortization													3,174	5,917	7,767
Impairment of oil and natural gas properties													0	0	0
Accretion of discount on asset retirement obligations													16	63	526
General and administrative													-3,342	23,125	14,394
Other operating items													-134	-25,950	-194
Total costs and expenses													108	5,595	42,313
Operating income (loss)													3,541	3,541	36,336
Interest expense, net													-92,049	-99,815	-73,489
Gain (loss) on derivative financial instruments													87,565	1,439	62,812
Other income (expense)													226	-1,068	238
Equity income (loss)													0	0	0
Net earnings (loss) from consolidated subsidiaries													121,386	118,107	-1,419,182
Total other income (expense)													117,128	18,663	-1,429,621
Income (loss) before income taxes													120,669	22,204	-1,393,285
Income tax expense													0	0	0
Net income (loss)													120,669	22,204	-1,393,285
Guarantor Subsidiaries [Member]
Oil and natural gas													614,889	582,158	467,960
Oil and natural gas production													77,334	63,716	84,790
Gathering and transportation													97,784	97,166	102,875
Depletion, depreciation and amortization													244,761	225,499	295,389
Impairment of oil and natural gas properties													0	108,546	1,346,749
Accretion of discount on asset retirement obligations													2,107	1,881	3,361
General and administrative													66,686	66,558	69,424
Other operating items													5,459	-151,549	17,223
Total costs and expenses													494,131	411,817	1,919,811
Operating income (loss)													120,758	170,341	-1,451,851
Interest expense, net													0	0	-3
Gain (loss) on derivative financial instruments													0	-177	3,321
Other income (expense)													0	229	731
Equity income (loss)													0	0	0
Net earnings (loss) from consolidated subsidiaries													0	0	0
Total other income (expense)													0	52	4,049
Income (loss) before income taxes													120,758	170,393	-1,447,802
Income tax expense													0	0	0
Net income (loss)													120,758	170,393	-1,447,802
Non-Guarantor Subsidiaries [Member]
Oil and natural gas													41,731	43,015	0
Oil and natural gas production													16,598	17,092	0
Gathering and transportation													3,790	3,479	0
Depletion, depreciation and amortization													15,634	14,359	0
Impairment of oil and natural gas properties													0	0	0
Accretion of discount on asset retirement obligations													567	570	0
General and administrative													2,576	2,195	0
Other operating items													-10	-19	0
Total costs and expenses													39,155	37,676	0
Operating income (loss)													2,576	5,339	0
Interest expense, net													-2,235	-2,774	0
Gain (loss) on derivative financial instruments													100	-1,582	0
Other income (expense)													15	11	0
Equity income (loss)													172	-53,280	28,620
Net earnings (loss) from consolidated subsidiaries													0	0	0
Total other income (expense)													-1,948	-57,625	28,620
Income (loss) before income taxes													628	-52,286	28,620
Income tax expense													0	0	0
Net income (loss)													628	-52,286	28,620
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
Other income (expense)													0	0	0
Equity income (loss)													0	0	0
Net earnings (loss) from consolidated subsidiaries													-121,386	-118,107	1,419,182
Total other income (expense)													-121,386	-118,107	1,419,182
Income (loss) before income taxes													-121,386	-118,107	1,419,182
Income tax expense													0	0	0
Net income (loss)													($121,386)	($118,107)	$1,419,182
[1]	Operating income (loss) for the first quarter and the fourth quarter of 2013 includes $10.7 million and $97.8 million, respectively, of impairments of oil and natural gas properties. See "Note 2. Summary of significant accounting policies" for further discussion.
[2]	Net income (loss) for the third quarter of 2013 includes a $91.5 million impairment to our investment in TGGT as a result of the carrying value exceeding the fair value. The impairment was reduced by $4.7 million in the fourth quarter of 2013 to $86.8 million as a result of final closing adjustments, fees and transaction expenses related to the sale of our equity investment in TGGT. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion.
[3]	Net income (loss) for the first quarter of 2013 includes a gain of $187.0 million from our contribution of oil and natural gas properties to Compass. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion.

Condensed_Consolidating_Financ4

Condensed Consolidating Financial Statements (Schedule Of Condensed Consolidating Statement Of Cash Flows) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net cash provided by (used in) operating activities	$362,093	$350,634	$514,786
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	-402,566	-1,297,252	-536,923
Restricted cash	-3,400	49,515	85,840
Equity method investments	1,749	236,289	-14,907
Proceeds from disposition of property and equipment	187,655	749,628	38,045
Distributions received from Compass	0	0
Net changes in advances to joint ventures	-5,026	10,645	851
Advances/investments with affiliates	0	0	0
Other	0	-1,303	0
Net cash used in investing activities	-221,588	-252,478	-427,094
Borrowings under credit agreements	100,000	1,004,523	53,000
Repayments under credit agreements	-964,970	-1,022,785	-93,000
Proceeds received from issuance of 2022 Notes	500,000	0	0
Proceeds from issuance of common shares, net	271,773	1,712	1,968
Payment of common share dividends	-41,060	-43,214	-34,358
Compass cash distribution	0	0
Deferred financing costs and other	-10,290	-33,553	-1,655
Payments of common shares repurchased	-136	0	0
Net cash used in financing activities	-144,683	-93,317	-74,045
Net increase (decrease) in cash	-4,178	4,839	13,647
Cash at beginning of period	50,483	45,644	31,997
Cash at end of period	46,305	50,483	45,644
Resources [Member]
Net cash provided by (used in) operating activities	-84,067	-32,678	182,143
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	-2,531	-15,767	-77,006
Restricted cash	0	0	0
Equity method investments	0	0	0
Proceeds from disposition of property and equipment	99,612	244,500	15,161
Distributions received from Compass	5,856	3,825
Net changes in advances to joint ventures	0	0	0
Advances/investments with affiliates	125,612	-59,575	-59,126
Other		-1,303
Net cash used in investing activities	228,549	171,680	-120,971
Borrowings under credit agreements	100,000	967,766	53,000
Repayments under credit agreements	-959,874	-1,015,900	-93,000
Proceeds received from issuance of 2022 Notes	500,000
Proceeds from issuance of common shares, net	271,773	1,712	1,968
Payment of common share dividends	-41,060	-43,214	-34,358
Compass cash distribution	0	0
Deferred financing costs and other	-10,188	-33,317	-1,655
Payments of common shares repurchased	-136
Net cash used in financing activities	-139,485	-122,953	-74,045
Net increase (decrease) in cash	4,997	16,049	-12,873
Cash at beginning of period	81,840	65,791	78,664
Cash at end of period	86,837	81,840	65,791
Guarantor Subsidiaries [Member]
Net cash provided by (used in) operating activities	428,029	365,770	332,643
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	-395,974	-1,242,667	-459,917
Restricted cash	-3,400	49,515	85,840
Equity method investments	1,749	236,289	-14,907
Proceeds from disposition of property and equipment	95,594	505,128	22,884
Distributions received from Compass	0	0
Net changes in advances to joint ventures	-5,026	10,645	851
Advances/investments with affiliates	-125,612	59,575	59,126
Other		0
Net cash used in investing activities	-432,669	-381,515	-306,123
Borrowings under credit agreements	0	0	0
Repayments under credit agreements	0	0	0
Proceeds received from issuance of 2022 Notes	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
Payments of common shares repurchased	0
Net cash used in financing activities	0	0	0
Net increase (decrease) in cash	-4,640	-15,745	26,520
Cash at beginning of period	-35,892	-20,147	-46,667
Cash at end of period	-40,532	-35,892	-20,147
Non-Guarantor Subsidiaries [Member]
Net cash provided by (used in) operating activities	18,131	17,542	0
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	-4,061	-38,818	0
Restricted cash	0	0	0
Equity method investments	0	0	0
Proceeds from disposition of property and equipment	-7,551	0	0
Distributions received from Compass	0	0
Net changes in advances to joint ventures	0	0	0
Advances/investments with affiliates	0	0	0
Other		0
Net cash used in investing activities	-11,612	-38,818	0
Borrowings under credit agreements	0	36,757	0
Repayments under credit agreements	-5,096	-6,885	0
Proceeds received from issuance of 2022 Notes	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	-102	-236	0
Payments of common shares repurchased	0
Net cash used in financing activities	-11,054	25,811	0
Net increase (decrease) in cash	-4,535	4,535	0
Cash at beginning of period	4,535	0	0
Cash at end of period	0	4,535	0
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
Restricted cash	0	0	0
Equity method investments	0	0	0
Proceeds from disposition of property and equipment	0	0	0
Distributions received from Compass	-5,856	-3,825
Net changes in advances to joint ventures	0	0	0
Advances/investments with affiliates	0	0	0
Other		0
Net cash used in investing activities	-5,856	-3,825	0
Borrowings under credit agreements	0	0	0
Repayments under credit agreements	0	0	0
Proceeds received from issuance of 2022 Notes	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
Payments of common shares repurchased	0
Net cash used in financing activities	5,856	3,825	0
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_unaud2

Quarterly Financial Data (unaudited) (Schedule Of Quarterly Financial Information) (Details) (USD $)	3 Months Ended												12 Months Ended
Share data in Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and natural gas revenues	$127,789,000	$151,042,000	$182,966,000	$198,472,000	$180,440,000		$165,314,000		$150,332,000		$138,223,000		$660,269,000	$634,309,000	$546,609,000
Operating income (loss)	3,341,000	22,799,000	43,312,000	57,423,000	-79,331,000	[1]	15,594,000	[1]	33,883,000	[1]	209,075,000	[1]	126,875,000	179,221,000	-1,415,515,000
Net income (loss)	81,413,000	41,569,000	2,293,000	-4,606,000	-122,863,000	[2],[3]	-98,651,000	[2],[3]	85,598,000	[2],[3]	158,120,000	[2],[3]	120,669,000	22,204,000	-1,393,285,000
Net income (loss) per basic common share	$0.30	$0.15	$0.01	($0.02)	($0.57)		($0.46)		$0.40		$0.74		$0.45	$0.10	($6.50)
Weighted average shares	271,053	270,631	270,492	260,716	215,410		215,056		214,788		214,784		268,258	215,011	214,321
Net income (loss) per diluted common share	$0.30	$0.15	$0.01	($0.02)	($0.57)		($0.46)		$0.40		$0.74		$0.45	$0.10	($6.50)
Weighted average shares	271,053	272,066	271,226	260,716	215,410		215,056		216,023		214,861		268,376	230,912	214,321
Impairment of oil and natural gas properties					97,800,000						10,700,000		0	108,546,000	1,346,749,000
Equity Method Investment, Other than Temporary Impairment														86,800,000
Gain (Loss) on Disposition of Property Plant Equipment													17,000	185,163,000	-1,303,000
Compass [Member]
Gain (Loss) on Disposition of Property Plant Equipment											187,000,000			186,400,000
TGGT Holdings, LLC [Member]
Equity Method Investment, Other than Temporary Impairment					86,800,000		91,500,000
Reduction to previously recognized impairment due to final closing adjustments					$4,700,000
[1]	Operating income (loss) for the first quarter and the fourth quarter of 2013 includes $10.7 million and $97.8 million, respectively, of impairments of oil and natural gas properties. See "Note 2. Summary of significant accounting policies" for further discussion.
[2]	Net income (loss) for the third quarter of 2013 includes a $91.5 million impairment to our investment in TGGT as a result of the carrying value exceeding the fair value. The impairment was reduced by $4.7 million in the fourth quarter of 2013 to $86.8 million as a result of final closing adjustments, fees and transaction expenses related to the sale of our equity investment in TGGT. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion.
[3]	Net income (loss) for the first quarter of 2013 includes a gain of $187.0 million from our contribution of oil and natural gas properties to Compass. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion.

Supplemental_Information_Relat2

Supplemental Information Relating To Oil And Natural Gas Producing Activities (unaudited) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Valuation of proved reserves on discounted rate	10.00%
Reference prices per bbl of oil	94.99	96.78	94.71
Reference prices per mmbtu of natural gas	4.35	3.67	2.76
Reference prices per Barrel of Natural Gas Liquids	33.03	39.92	46.57

Supplemental_Information_Relat3

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) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved property acquisition costs	$10,562,000		$754,370,000		$0
Unproved property acquisition costs	0		232,020,000		3,349,000
Total property acquisition costs	10,562,000		986,390,000	[1]	3,349,000
Development	354,199,000		231,447,000		346,017,000
Exploration costs	5,906,000	[2]	38,579,000	[3]	57,325,000	[4]
Lease acquisitions and other	9,681,000		14,835,000		44,546,000	[5]
Capitalized asset retirement costs	576,000		514,000		971,000
Depletion per Boe	11.42		8.82		9.11
Depletion per Mcfe	1.9		1.47		1.52
Bossier Shale [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	5,900,000
Eagle Ford [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs			29,200,000
Haynesville Shale [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs					40,100,000
Marcellus Shale [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs			9,400,000		17,200,000
BG Group [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acreage reimbursements					$2,100,000
[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 2014 include $5.9 million in the Bossier shale in North Louisiana.
[3]	Exploration costs in 2013 include $29.2 million in the Eagle Ford shale and $9.4 million in the Marcellus shale.
[4]	Exploration costs in 2012 include $40.1 million in the Haynesville shale $17.2 million in the Marcellus shale.
[5]	Lease acquisition costs in 2012 are net of acreage reimbursements from BG Group totaling $2.1 million.

Supplemental_Information_Relat4

Supplemental Information Relating To Oil And Natural Gas Producing Activities (unaudited) (Reserve Quantities) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
	bbl		bbl		bbl
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	1,542,587		1,252,273		696,147
Revisions due to reclassification of reserves					8,736,000
Revision due to performance and cost					246,451,000
Oil [Member]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Beginning balance	15,378,000		5,570,000		6,354,000
Purchase of reserves in place	0	[1]	16,022,000	[2]	0
Discoveries and extensions	4,164,000	[3]	5,960,000	[4]	492,000	[5]
Changes in price	45,000		457,000		-110,000
Revisions to Proved Developed and Undeveloped Reserves	1,737,000	[6]	-3,219,000	[7]	-463,000	[8]
Sales of reserves in place	-1,401,000	[9]	-8,224,000	[10]	0
Production	-2,236,000		-1,188,000		-703,000
Ending balance	17,687,000		15,378,000		5,570,000
Proved developed	14,429,000		11,274,000		4,371,000
Proved undeveloped	3,258,000		4,104,000		1,199,000
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	1,016,479,000		936,132,000		1,291,464,000
Purchase of reserves in place	7,316,000	[1]	290,933,000	[2]	0
Discoveries and extensions	69,902,000	[3]	46,834,000	[4]	96,615,000	[5]
Changes in price	167,302,000		272,614,000		-466,238,000
Revisions to Proved Developed and Undeveloped Reserves	120,850,000	[6]	-106,695,000	[7]	199,784,000	[8]
Sales of reserves in place	-105,841,000	[9]	-270,018,000	[10]	-2,837,000
Production	-120,980,000		-153,321,000		-182,656,000
Ending balance	1,155,028,000		1,016,479,000		936,132,000
Proved developed	502,314,000		657,116,000		917,326,000
Proved undeveloped	652,714,000		359,363,000		18,806,000
Natural Gas Liquids [Member]
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Beginning balance	2,583,000		6,639,000		0
Purchase of reserves in place	0	[1]	2,201,000	[2]	0
Discoveries and extensions	107,000	[3]	513,000	[4]	424,000	[5]
Changes in price	127,000		686,000		0
Revisions to Proved Developed and Undeveloped Reserves	-8,000	[6]	-741,000	[7]	6,724,000	[8]
Sales of reserves in place	-2,144,000	[9]	-6,472,000	[10]	0
Production	-224,000		-243,000		-509,000
Ending balance	441,000		2,583,000		6,639,000
Proved developed	387,000		2,088,000		4,784,000
Proved undeveloped	54,000		495,000		1,855,000
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)	1,124,245,000	[11]	1,009,386,000	[11]	1,329,588,000	[11]
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place (Mcfe)	7,316,000	[1],[11]	400,271,000	[11],[2]	0	[11]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions (Mcfe)	95,528,000	[11],[3]	85,672,000	[11],[4]	102,111,000	[11],[5]
Revisions To Proved Developed And Undeveloped Reserves Due To Changes In Price (Mcfe)	168,334,000	[11]	279,472,000	[11]	-466,898,000	[11]
Revisions to Proved Developed and Undeveloped Reserves due to other Factors (Mcfe)	131,224,000	[11],[6]	-130,455,000	[11],[7]	237,350,000	[11],[8]
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place (Mcfe)	-127,111,000	[11],[9]	-358,194,000	[10],[11]	-2,837,000	[11]
Proved Developed and Undeveloped Reserves, Production (Mcfe)	-135,740,000	[11]	-161,907,000	[11]	-189,928,000	[11]
Proved Developed and Undeveloped Reserves, Net (Mcfe)	1,263,796,000	[11]	1,124,245,000	[11]	1,009,386,000	[11]
Proved developed	591,210,000		737,291,000		972,256,000
Proved Undeveloped Reserves (Energy)	672,586,000		386,954,000		37,130,000
Holly 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)	5,836,000
Appalachia [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)					59,455,000
Revisions to Proved Developed and Undeveloped Reserves due to other Factors (Mcfe)	45,878,000
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)			33,591,000
East Texas/North Louisiana [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)					25,626,000
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)			1,486,000
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions (Mcfe)					17,027,000
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)			115,718,000
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions (Mcfe)	26,148,000		36,501,000
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place (Mcfe)			-30,582,000
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)			259,991,000
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions (Mcfe)	48,698,000		10,211,000
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)	19,664,000
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)	67,095,000
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)			24,558,000
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions (Mcfe)			3,881,000
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place (Mcfe)			-327,608,000
[1]	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.
[2]	Purchases of reserves in place include 115,718 Mmcfe in the Eagle Ford shale, 259,991 Mmcfe in the Haynesville shale, and 24,558 Mmcfe for our proportionate share of Compass's acquisition of shallow Cotton Valley assets in East Texas/North Louisiana.
[3]	New discoveries and extensions in 2014 included 48,698 Mmcfe in the Haynesville shale, 26,148 Mmcfe in the Eagle Ford Shale and 19,664 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.
[4]	New discoveries and extensions in 2013 include 36,501 Mmcfe in the Eagle Ford shale, 33,591 Mmcfe in the Marcellus shale, 10,211 Mmcfe in the Haynesville shale, 3,881 Mmcfe for conventional properties held by Compass in the Permian Basin, and 1,486 Mmcfe for shale properties in the Permian Basin.
[5]	New discoveries and extensions in 2012 include 25,626 Mmcfe in East Texas/North Louisiana, primarily in the Haynesville shale, 59,455 Mmcfe in the Marcellus shale and 17,027 Mmcfe in the Permian Basin.
[6]	Total revisions due to Other factors include upward revisions of approximately 67,095 Mmcfe in the Shelby area, approximately 45,878 Mmcfe in the Appalachia region, and approximately 5,836 Mmcfe in the Holly area. The upward revisions were primarily due to improved well performance resulting from enhanced well designs and completion techniques.
[7]	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.
[8]	Total revisions due to Other factors in 2012 include approximately 8,736 Mmcfe of Proved Undeveloped Reserves that were reclassified to unproved reserves as a result of a slower development schedule due to depressed natural gas prices, which extended their scheduled development beyond a five-year development horizon. The change also includes a positive revision of 246,451 Mmcfe resulting from unproved performance and cost reductions.
[9]	Sales of reserves in place in 2014 consist primarily of the sale of our entire interest in Compass.
[10]	Sales of reserves in place in 2013 include 327,608 Mmcfe as a result of our contribution of properties to Compass and 30,582 Mmcfe from the sale of undeveloped properties in the Eagle Ford in connection with the Participation Agreement.
[11]	The above reserves do not include our equity interest in OPCO, which was not significant in any period presented.

Supplemental_Information_Relat5

Supplemental Information Relating To Oil And Natural Gas Producing Activities (unaudited) (Standardized Measure Of Discounted Future Net Cash Flows) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Extractive Industries [Abstract]
Future cash inflows	$6,097,207	$5,176,030	$3,187,480
Future production costs	2,094,796	2,207,230	1,824,702
Future development costs	1,124,873	904,116	266,726
Future income taxes	0	0	0
Future net cash flows	2,877,538	2,064,684	1,096,052
Discount of future net cash flows at 10% per annum	1,334,951	812,411	399,905
Standardized measure of discounted future net cash flows	$1,542,587	$1,252,273	$696,147

Supplemental_Information_Relat6

Supplemental Information Relating To Oil And Natural Gas Producing Activities (unaudited) (Principal Sources Of Change In The Standardized Measure) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Sales and transfers of oil and natural gas produced	($464,369)	($450,415)	($339,125)
Net changes in prices and production costs	279,944	582,725	-1,258,493
Extensions and discoveries, net of future development and production costs	196,796	197,223	90,633
Development costs during the period	189,155	55,196	204,929
Changes in estimated future development costs	-254,737	-251,484	404,414
Revisions of previous quantity estimates (includes revisions-transfer of Proved Undeveloped Reserves to probable reserves)	412,296	98,283	-336,142
Sales of reserves in place	-148,226	-315,758	-3,604
Purchase of reserves in place	13,507	604,366	0
Accretion of discount before income taxes	125,227	69,615	165,755
Changes in timing and other	-59,279	-33,625	94,129
Net change in income taxes	0	0	247,189
Net change	$290,314	$556,126	($730,315)

Supplemental_Information_Relat7

Supplemental Information Relating To Oil And Natural Gas Producing Activities (unaudited) (Costs Not Subject To Amortization) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	$228,553
Exploration and development	16,366
Capitalized interest	31,106
Total	276,025
2014 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	9,737
Exploration and development	10,797
Capitalized interest	11,871
Total	32,405
2013 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	71,524
Exploration and development	73
Capitalized interest	8,737
Total	80,334
2012 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	3,038
Exploration and development	524
Capitalized interest	6,796
Total	10,358
2011 and prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	144,254
Exploration and development	4,972
Capitalized interest	3,702
Total	$152,928