10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________

FORM 10-Q

______________________________

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2016

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from             to            

Commission File Number 001-32743

______________________________ 

EXCO RESOURCES, INC.

(Exact name of registrant as specified in its charter)

______________________________

Texas	74-1492779
(State of incorporation)	(I.R.S. Employer Identification No.)
12377 Merit Drive Suite 1700, LB 82 Dallas, Texas	75251
(Address of principal executive offices)	(Zip Code)

(214) 368-2084

(Registrant’s telephone number, including area code)

______________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   YES  x    NO  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant is required to submit and post such files).    YES  x    NO  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	o	Accelerated filer	x
Non-accelerated filer	o  (Do not check if a smaller reporting company)	Smaller reporting company	o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    YES  o    NO  x

The number of shares of common stock, par value $0.001 per share, outstanding as of October 28, 2016 was 282,445,821.

EXCO RESOURCES, INC.

INDEX

PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Condensed Consolidated Balance Sheets at September 30, 2016 and December 31, 2015	2
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2016 and 2015	3
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2016 and 2015	4
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Nine Months Ended September 30, 2016 and 2015	5
	Notes to Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	52
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	52
Item 1A.	Risk Factors	52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53
Item 6.	Exhibits	53
	Signatures	54

1

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)	September 30, 2016			December 31, 2015
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	3,534		$	12,247
Restricted cash	18,434			21,220
Accounts receivable, net:
Oil and natural gas	53,439			37,236
Joint interest	17,949			22,095
Other	3,871			8,894
Derivative financial instruments	5,952			39,499
Inventory and other	7,630			8,610
Total current assets	110,809			149,801
Equity investments	31,973			40,797
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	93,511			115,377
Proved developed and undeveloped oil and natural gas properties	2,946,641			3,070,430
Accumulated depletion	(2,690,611		)	(2,627,763		)
Oil and natural gas properties, net	349,541			558,044
Other property and equipment, net	24,058			27,812
Deferred financing costs, net	5,000			8,408
Derivative financial instruments	1,455			6,109
Goodwill	163,155			163,155
Total assets	$	685,991		$	954,126
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	56,056		$	88,049
Revenues and royalties payable	121,312			106,163
Accrued interest payable	3,774			7,846
Current portion of asset retirement obligations	428			845
Income taxes payable	—			—
Derivative financial instruments	10,353			16
Current maturities of long-term debt	50,000			50,000
Total current liabilities	241,923			252,919
Long-term debt	1,256,068			1,320,279
Deferred income taxes	1,775			—
Derivative financial instruments	1,189			—
Asset retirement obligations and other long-term liabilities	22,626			43,251
Shareholders’ equity:
Common shares, $0.001 par value; 780,000,000 authorized shares; 283,040,484 shares issued and 282,445,821 shares outstanding at September 30, 2016; 283,633,996 shares issued and 283,039,333 shares outstanding at December 31, 2015	283			276
Additional paid-in capital	3,537,393			3,522,153
Accumulated deficit	(4,367,634		)	(4,177,120		)
Treasury shares, at cost; 594,663 shares at September 30, 2016 and December 31, 2015	(7,632		)	(7,632		)
Total shareholders’ equity	(837,590		)	(662,323		)
Total liabilities and shareholders’ equity	$	685,991		$	954,126

See accompanying notes.

2

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands, except per share data)	2016			2015			2016			2015
Revenues:
Oil	$	16,215		$	27,444		$	49,688		$	79,872
Natural gas	54,647			56,300			127,044			184,275
Purchased natural gas and marketing	6,324			6,773			15,335			21,012
Total revenues	77,186			90,517			192,067			285,159
Costs and expenses:
Oil and natural gas operating costs	8,797			12,669			25,835			41,745
Production and ad valorem taxes	3,811			5,944			13,308			16,408
Gathering and transportation	27,979			23,743			79,828			74,243
Purchased natural gas	6,586			6,991			17,273			21,571
Depletion, depreciation and amortization	15,910			52,013			63,995			176,160
Impairment of oil and natural gas properties	—			339,393			160,813			1,010,047
Accretion of discount on asset retirement obligations	325			574			2,006			1,698
General and administrative	10,746			13,393			38,626			41,227
Other operating items	(1,110		)	(228		)	23,936			1,118
Total costs and expenses	73,044			454,492			425,620			1,384,217
Operating income (loss)	4,142			(363,975		)	(233,553		)	(1,099,058		)
Other income (expense):
Interest expense, net	(16,997		)	(27,761		)	(54,186		)	(80,822		)
Gain (loss) on derivative financial instruments	8,209			37,348			(11,632		)	54,427
Gain on extinguishment of debt	57,421			—			119,374			—
Other income	12			21			37			119
Equity loss	(823		)	(152		)	(8,824		)	(1,452		)
Total other income (expense)	47,822			9,456			44,769			(27,728		)
Income (loss) before income taxes	51,964			(354,519		)	(188,784		)	(1,126,786		)
Income tax expense	1,028			—			1,775			—
Net income (loss)	$	50,936		$	(354,519	)	$	(190,559	)	$	(1,126,786	)
Earnings (loss) per common share:
Basic:
Net income (loss)	$	0.18		$	(1.30	)	$	(0.68	)	$	(4.14	)
Weighted average common shares outstanding	279,873			273,348			279,008			272,147
Diluted:
Net income (loss)	$	0.18		$	(1.30	)	$	(0.68	)	$	(4.14	)
Weighted average common shares and common share equivalents outstanding	281,045			273,348			279,008			272,147

See accompanying notes.

3

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
(in thousands)	2016			2015
Operating Activities:
Net loss	$	(190,559	)	$	(1,126,786	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Deferred income tax expense	1,775			—
Depletion, depreciation and amortization	63,995			176,160
Equity-based compensation expense	14,558			4,045
Accretion of discount on asset retirement obligations	2,006			1,698
Impairment of oil and natural gas properties	160,813			1,010,047
Loss from equity investments	8,824			1,452
(Gain) loss on derivative financial instruments	11,632			(54,427		)
Cash receipts of derivative financial instruments	38,097			88,977
Amortization of deferred financing costs and discount on debt issuance	7,250			11,083
Other non-operating items	24,068			(13		)
Gain on extinguishment of debt	(119,374		)	—
Effect of changes in:
Restricted cash with related party	2,100			(1,500		)
Accounts receivable	(12,752		)	59,238
Other current assets	(1,207		)	1,062
Accounts payable and other liabilities	(14,966		)	(44,180		)
Net cash provided by (used in) operating activities	(3,740		)	126,856
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment	(70,455		)	(269,708		)
Property acquisitions	—			(7,608		)
Proceeds from disposition of property and equipment	11,242			7,397
Restricted cash	686			4,016
Net changes in advances to joint ventures	2,377			8,594
Equity investments and other	—			1,455
Net cash used in investing activities	(56,150		)	(255,854		)
Financing Activities:
Borrowings under EXCO Resources Credit Agreement	390,897			97,500
Repayments under EXCO Resources Credit Agreement	(243,797		)	—
Payments on Exchange Term Loan	(38,056		)	—
Repurchases of senior unsecured notes	(53,298		)	—
Proceeds from issuance of common shares, net	—			9,829
Deferred financing costs and other	(4,569		)	(4,125		)
Net cash provided by financing activities	51,177			103,204
Net decrease in cash	(8,713		)	(25,794		)
Cash at beginning of period	12,247			46,305
Cash at end of period	$	3,534		$	20,511
Supplemental Cash Flow Information:
Cash interest payments	$	51,975		$	81,913
Income tax payments	—			—
Supplemental non-cash investing and financing activities:
Capitalized equity-based compensation	$	432		$	2,861
Capitalized interest	3,939			10,121

See accompanying notes.

4

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

	Common shares				Treasury shares					Additional paid-in capital		Accumulated deficit			Total shareholders’ equity
(in thousands)	Shares		Amount		Shares		Amount
Balance at December 31, 2014	274,352		$	270	(578	)	$	(7,615	)	$	3,502,209	$	(2,984,860	)	$	510,004
Issuance of common shares	5,882		6		—		—			9,875		—			9,881
Equity-based compensation	—		—		—		—			6,439		—			6,439
Restricted shares issued, net of cancellations	3,422		—		—		—			—		—			—
Common share dividends	—		—		—		—			—		3			3
Treasury share repurchases	—		—		(17	)	(17		)	—		—			(17		)
Net loss	—		—		—		—			—		(1,126,786		)	(1,126,786		)
Balance at September 30, 2015	283,656		$	276	(595	)	$	(7,632	)	$	3,518,523	$	(4,111,643	)	$	(600,476	)
Balance at December 31, 2015	283,634		$	276	(595	)	$	(7,632	)	$	3,522,153	$	(4,177,120	)	$	(662,323	)
Issuance of common shares	243		—		—		—			—		—			—
Equity-based compensation	—		—		—		—			15,240		—			15,240
Restricted shares issued, net of cancellations	(837	)	7		—		—			—		—			7
Common share dividends	—		—		—		—			—		45			45
Net loss	—		—		—		—			—		(190,559		)	(190,559		)
Balance at September 30, 2016	283,040		$	283	(595	)	$	(7,632	)	$	3,537,393	$	(4,367,634	)	$	(837,590	)

See accompanying notes.

5

EXCO RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.Organization and basis of presentation

Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” are to EXCO Resources, Inc. and its consolidated subsidiaries.

We are an independent oil and natural gas company engaged in the exploration, exploitation, acquisition, development and production of onshore U.S. oil and natural gas properties with a focus on shale resource plays. Our principal operations are conducted in certain key U.S. oil and natural gas areas including Texas, Louisiana and the Appalachia region. The following is a brief discussion of our producing regions.

•East Texas and North Louisiana

The East Texas and North Louisiana regions are primarily comprised of our Haynesville and Bossier shale assets. We have a joint venture with BG Group, plc ("BG Group"), a wholly owned subsidiary of Royal Dutch Shell, plc, covering an undivided 50% interest in the majority of our Haynesville and Bossier shale assets in East Texas and North Louisiana. The East Texas and North Louisiana regions also include certain assets outside of the joint venture in the Haynesville and Bossier shales. We serve as the operator for most of our properties in the East Texas and North Louisiana regions.

•South Texas

The South Texas region is primarily comprised of our Eagle Ford shale assets. We serve as the operator for most of our properties in the South Texas region.

•Appalachia

The Appalachia region is primarily comprised of Marcellus shale assets as well as shallow conventional assets in other formations. We have a joint venture with BG Group covering our 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. On July 1, 2016, we closed the sale of our interests in shallow conventional assets located in Pennsylvania and retained an overriding royalty interest in each well, and on October 3, 2016, we closed the sale of our interests in shallow conventional assets located in West Virginia. See "Note 3. Divestitures" for additional discussion.

The accompanying Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015, Condensed Consolidated Statements of Operations for the three and nine months endedSeptember 30, 2016 and 2015, Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the nine months endedSeptember 30, 2016 and 2015 are for EXCO and its subsidiaries. The unaudited Condensed Consolidated Financial Statements and related footnotes are presented in accordance with generally accepted accounting principles in the United States ("GAAP"). Certain reclassifications have been made to prior period information to conform to current period presentation.

We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") and in the opinion of management, such financial statements reflect all adjustments necessary to fairly present the consolidated financial position of EXCO at September 30, 2016 and its results of operations and cash flows for the periods presented. We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with GAAP pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. These unaudited interim financial statements should be read in conjunction with our audited consolidated financial statements and related footnotes included in EXCO's Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on March 2, 2016 ("2015 Form 10-K").

In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures. The results of operations for the interim periods are not necessarily indicative of the results we expect for the full year.

6

Going Concern Presumption and Management’s Plans

These unaudited Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. Our liquidity and ability to maintain compliance with debt covenants have been negatively impacted by the prolonged depressed oil and natural gas price environment, levels of indebtedness, and gathering, transportation and certain other commercial contracts. As of September 30, 2016, the Company had $3.5 million in cash and cash equivalents, $75.4 million of availability under its credit agreement ("EXCO Resources Credit Agreement") and a working capital deficit of $131.1 million. We have substantial interest payment obligations related to our debt over the next twelve months. The next borrowing base redetermination under the EXCO Resources Credit Agreement is expected to occur in November 2016. The lenders party to the EXCO Resources Credit Agreement have considerable discretion in setting our borrowing base, and we are unable to predict the outcome of any future redeterminations.

Our plans to improve near-term liquidity primarily include the issuance of additional indebtedness and we are engaged in discussions with potential lenders. The availability and terms of this financing may be dependent upon our ability to reduce fixed commitments including gathering and transportation contracts. We continue to negotiate a consensual restructuring of gathering and transportation contracts with our counterparties. If we are not able to execute transactions to improve our financial condition, we do not believe we will be able to comply with all of the covenants under the EXCO Resources Credit Agreement or have sufficient liquidity to conduct our business operations based on existing conditions and estimates during the next twelve months. Management’s plans are intended to mitigate these conditions; however, our ability to execute these plans is conditioned upon factors including the availability of capital markets, market conditions, and the actions of counterparties. There is no assurance any such transactions will occur.  

As of September 30, 2016, we were in compliance with the financial covenants under the EXCO Resources Credit Agreement. We are required to 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, which includes unused commitments in the definition of consolidated current assets. The inclusion of the unused commitments has historically allowed us to maintain compliance with the Consolidated Current Ratio covenant under the EXCO Resources Credit Agreement. Therefore, the reduction in unused commitments as a result of borrowings under the EXCO Resources Credit Agreement or further reductions to our borrowing base as part of the redetermination process will negatively impact our Consolidated Current Ratio and liquidity.

The EXCO Resources Credit Agreement does not permit our ratio of senior secured indebtedness to consolidated EBITDAX ("Senior Secured Indebtedness Ratio") to be greater than 2.5 to 1.0 as of the end of any fiscal quarter. Senior secured indebtedness utilized in the Senior Secured Indebtedness Ratio excludes the Second Lien Term Loans (as defined below) and any other secured indebtedness subordinated to the EXCO Resources Credit Agreement. The Company's compliance with this covenant will be negatively impacted unless we are able to increase our EBITDAX, generate positive free cash flows and/or find other sources of capital to reduce indebtedness under the EXCO Resources Credit Agreement.

As a result of the impact of the aforementioned factors on our financial results and condition, we anticipate that we will not meet the minimum requirement under the Consolidated Current Ratio and the Senior Secured Indebtedness Ratio for the twelve-month period following the date of these unaudited Condensed Consolidated Financial Statements. We may not be in compliance with these covenants as early as the fiscal quarter ending December 31, 2016 depending on our future financial and operating results and the outcome of the borrowing base redetermination process. Furthermore, our liquidity is not expected to be sufficient to conduct our business operations for the twelve-month period following the date of these unaudited Condensed Consolidated Financial Statements. If we are not able to comply with our debt covenants or do not have sufficient liquidity to conduct our business operations in future periods, we may be required, but unable, to refinance all or part of our existing debt, seek covenant relief from our lenders, sell assets, incur additional indebtedness, or issue 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. Therefore, our ability to continue our planned principal business operations would be dependent on the actions of our lenders or obtaining additional debt and/or equity financing to repay outstanding indebtedness under the EXCO Resources Credit Agreement. These factors raise substantial doubt about our ability to continue as a going concern.

The EXCO Resources Credit Agreement and the term loan credit agreements governing our senior secured second lien term loans due October 26, 2020 (“Second Lien Term Loans”) require our annual financial statements to include a report from our independent registered public accounting firm without an explanatory paragraph related to our ability to continue as a going concern. If the substantial doubt about our ability to continue as a going concern still exists at December 31, 2016 or if we fail to comply with the financial and other covenants in the EXCO Resources Credit Agreement or the Second Lien Term Loans, we would be in default under such agreement. Any event of default may cause a default or accelerate our obligations with respect to our other outstanding indebtedness, including our senior unsecured notes due September 15, 2018 (“2018 Notes”)

7

and senior unsecured notes due April 15, 2022 (“2022 Notes”), which could adversely affect our business, financial condition and results of operations.

The accompanying unaudited Condensed Consolidated Financial Statements do not include any adjustments to reflect the possible future effects of this uncertainty on the recoverability or classification of recorded asset amounts or the amounts or classification of liabilities.

Revisions of prior period information

On August 19, 2016, we formed Raider Marketing, LP ("Raider") through an internal merger to provide marketing services to EXCO and pursue independent business opportunities. Raider is a wholly owned subsidiary of EXCO and is the contractual counterparty by operation of Texas law to all of EXCO's gathering, transportation and marketing contracts in Texas and Louisiana. In connection with the formation of Raider and the Company's plans to pursue additional marketing opportunities, we have revised our presentation of third party natural gas purchases and sales to report these costs and revenues on a gross basis in the accompanying statements of operations in accordance with Financial Accounting Standards Board (“FASB”) Codification (“ASC”) 605, Revenue Recognition, beginning in the third quarter of 2016. Third party purchases and sales are now reported gross as "Purchased natural gas" expenses and "Purchased natural gas and marketing" revenues, respectively. Purchased natural gas and marketing revenues include revenue we receive as a result of selling natural gas that we purchase from third parties and marketing fees we receive from third parties. Purchased natural gas expenses include purchases from third parties plus an allocation of transportation costs. The transportation costs allocated to the third party purchases relate to our firm transportation agreements with unutilized commitments; therefore, the utilization of this transportation reduces the unutilized commitments that would have otherwise been allocated to our net share of production and incurred by EXCO.

We previously reported these transactions on a net basis in the financial statements due to the materiality associated with the income or loss generated from these purchases and sales, and the historical insignificance of the Company's marketing activities involving the purchases and sales of third party natural gas to our business strategies and operations. The net effect of these revisions did not impact our previously reported net income or loss, shareholders’ equity or cash flows. The Company evaluated the materiality of the revisions based on ASC 250, Accounting Changes and Error Corrections, and concluded the revisions to be immaterial corrections of an error.

The following table reflects the revisions to prior periods:

					Three months ended
(in thousands)					June 30, 2016			March 31, 2016
Gathering and transportation, previously reported					$	26,895		$	26,630
Revision of third party natural gas purchases and sales					(151		)	(1,525		)
Gathering and transportation, as currently reported					$	26,744		$	25,105
Purchased natural gas and marketing revenues					$	4,570		$	4,441
Purchased natural gas expenses					$	4,721		$	5,966
	Three months ended
(in thousands)	December 31, 2015		September 31, 2015		June 30, 2015			March 31, 2015
Natural gas revenues, previously reported	$	41,828	$	56,082	$	62,197		$	65,437
Revision of third party natural gas purchases and sales	368		218		184			157
Natural gas revenues, as currently reported	$	42,196	$	56,300	$	62,381		$	65,594
Purchased natural gas and marketing revenues	$	5,430	$	6,773	$	6,678		$	7,561
Purchased natural gas expenses	$	5,798	$	6,991	$	6,862		$	7,718

8

2.Significant accounting policies

We consider significant accounting policies to be those related to our estimates of proved reserves, oil and natural gas properties, derivatives, business combinations, equity-based compensation, goodwill, revenue recognition, asset retirement obligations and income taxes. The policies include significant estimates made by management using information available at the time the estimates were made. However, these estimates could change materially if different information or assumptions were used. These policies and others are summarized in our 2015 Form 10-K.

Recent accounting pronouncements

In August 2016, the FASB issued Accounting Standards Update ("ASU") No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments ("ASU 2016-15"). ASU 2016-15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows. The amendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees. ASU 2016-15 is effective for annual and interim periods beginning after December 15, 2017. We are currently assessing the potential impact of ASU 2016-15 on our consolidated financial condition and results of operations.

In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients ("ASU 2016-12"). ASU 2016-12 does not change the core principle of Topic 606 but improves the following aspects of Topic 606: assessing collectability, presentation of sales taxes, noncash considerations, completed contracts and contract modifications at transaction. ASU 2016-12 is effective for annual and interim periods beginning after December 15, 2017. We are currently assessing the potential impact of ASU 2016-12 on our consolidated financial condition and results of operations.

In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting ("ASU 2016-11"). The SEC Staff is rescinding the following SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. Specifically, registrants should not rely on the following SEC Staff Observer comments upon adoption of Topic 606: a) Revenue and Expense Recognition for Freight Services in Process which is codified in 605-20-S99-2; b) Accounting for Shipping and Handling Fees and Costs, which is codified in paragraph 605-45-S99-1; c) Accounting for Consideration Given by a Vendor to a Customer, which is codified in paragraph 605-50-S99-1 and d) Accounting for Gas-Balancing Arrangements (that is, use of the “entitlements method”), which is codified in paragraph 932-10-S99-5. We do not use the entitlements method of accounting and are not impacted by this specific SEC Staff Observer comment; however, we are assessing the potential impact of other SEC Staff Observer comments included in ASU 2016-11 on our consolidated financial condition and results of operations.

In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing ("ASU 2016-10"). ASU 2016-10 does not change the core principle of Topic 606 but clarifies the following two aspects of Topic 606: identifying performance obligations and the licensing implementation guidance, while retaining the related principles for those areas. ASU 2016-10 is effective for annual and interim periods beginning after December 15, 2017. We are currently assessing the potential impact of ASU 2016-10 on our consolidated financial condition and results of operations.

In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting ("ASU 2016-09"). ASU 2016-09 simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. ASU 2016-07 is effective for annual and interim periods beginning after December 15, 2016 and early adoption is permitted. We are currently assessing the potential impact of ASU 2016-09 on our consolidated financial condition and results of operations.

In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) ("ASU 2016-08"). ASU 2016-08 does not change the core principle of Topic 606 but clarifies the implementation guidance on principal versus agent considerations. ASU 2016-08 is effective for annual and interim periods beginning after December 15, 2017. We are currently assessing the potential impact of ASU 2016-08 on our consolidated financial condition and results of operations.

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In March 2016, the FASB issued ASU No. 2016-07, Investments - Equity Method and Joint Ventures (Topic 323): Simplifying the Transition to the Equity Method of Accounting ("ASU 2016-07"). ASU 2016-07 eliminates the requirement that when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence, an investor must adjust the investment, results of operations, and retained earnings retroactively on a step-by-step basis as if the equity method had been in effect during all previous periods that the investment had been held. Therefore, upon qualifying for the equity method of accounting, no retroactive adjustment of the investment is required. ASU 2016-07 is effective for annual and interim periods beginning after December 15, 2016 and early adoption is permitted. We do not currently have significant investments that are accounted for by a method other than the equity method and do not expect ASU 2016-07 to have a significant impact on our consolidated financial condition and results of operations.

3.Divestitures

South Texas transaction

On May 6, 2016, we closed a sale of certain non-core undeveloped acreage in South Texas and our interests in four producing wells for $11.5 million, subject to customary post-closing purchase price adjustments. Proceeds from the sale were used to reduce indebtedness under the EXCO Resources Credit Agreement.

Conventional asset divestitures

On July 1, 2016, we closed the sale of our interests in shallow conventional assets located in Pennsylvania and received an overriding royalty interest in each well and approximately $0.1 million, subject to customary post-closing purchase price adjustments. In addition, we retained all rights to other formations below the conventional depths in this region including the Marcellus and Utica shales. For the six months ended June 30, 2016, the divested assets produced approximately 6 Mmcfe per day and the revenues less direct operating expenses, excluding general and administrative costs, generated a net loss of less than $0.1 million. The asset retirement obligations related to the divested wells were $22.6 million on July 1, 2016.

On October 3, 2016, we closed the sale of our interests in shallow conventional assets located in West Virginia for approximately $4.5 million, subject to customary post-closing purchase price adjustments. We retained all rights to other formations below the conventional depths in this region including the Marcellus and Utica shales. For the nine months ended September 30, 2016, the divested assets produced approximately 4 Mmcfe per day and the revenues less direct operating expenses, excluding general and administrative costs, generated net income of $0.7 million. The asset retirement obligations related to the divested wells were $9.7 million on September 30, 2016.

In conjunction with the sales of our shallow conventional assets in Pennsylvania and West Virginia, the Company's field employee count in the Appalachia region has been reduced by 85% since December 31, 2015.

4.Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the nine months endedSeptember 30, 2016:

(in thousands)
Asset retirement obligations at beginning of period	$	41,648
Activity during the period:
Liabilities settled during the period	(59		)
Adjustment to liability due to divestitures (1)	(22,859		)
Accretion of discount	2,006
Asset retirement obligations at end of period	20,736
Less current portion	428
Long-term portion	$	20,308

(1) Adjustment to liability due to divestitures is primarily due to the sale of our conventional assets in Pennsylvania on July 1, 2016. See "Note 3. Divestitures" for additional information.

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Our asset retirement obligations are determined using discounted cash flow methodologies based on inputs and assumptions developed by management. We do not have any assets that are legally restricted for purposes of settling asset retirement obligations.

5.Oil and natural gas properties

We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. The majority of our undeveloped properties are held-by-production, which reduces the risk of impairment as a result of lease expirations. There were no impairments of unproved properties during the nine months endedSeptember 30, 2016 and we impaired $84.9 million of unproved properties during the nine months ended September 31, 2015.

At the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs ("ceiling test"). The ceiling test involves comparing the net book value of the full cost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record an impairment of our oil and natural gas properties. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our proved reserves by applying the average price as prescribed by the SEC, less estimated future expenditures (based on current costs) to develop and produce the proved reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects.

The ceiling test for each period presented was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing twelve-month simple average spot prices at the first of the month for natural gas at Henry Hub ("HH") and West Texas Intermediate ("WTI") crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in oil and natural gas prices between each of the periods and have a significant impact on our ceiling test limitation.

	Average spot prices
	Oil (per Bbl)		Natural gas (per Mmbtu)
September 30, 2016	$	41.68	$	2.24
June 30, 2016	43.12		2.24
March 31, 2016	46.26		2.40
December 31, 2015	50.28		2.59

We did not recognize an impairment to our proved oil and natural gas properties for the three months ended September 30, 2016, and we recognized impairments to our proved oil and natural gas properties of $160.8 million for the nine months ended September 30, 2016. We recognized impairments to our proved oil and natural gas properties of $339.4 million and $1.0 billionfor the three and nine months endedSeptember 30, 2015, respectively. The impairments were primarily due to the decline in oil and natural gas prices.  Furthermore, the fixed costs associated with certain gathering and transportation contracts continue to have a significant impact on the present value of our proved reserves. Oil and natural gas prices are volatile and we may incur additional impairments during 2016 if future oil and natural gas prices result in a decrease in the trailing twelve-month reference prices compared to September 30, 2016. The possibility and amount of any future impairments is difficult to predict, and will depend, in part, upon future oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves, future capital expenditures and operating costs.

During 2016, all of our proved undeveloped reserves, other than the proved undeveloped reserves associated with certain wells drilled and/or completed in 2016, were reclassified to unproved primarily due to the uncertainty regarding the financing required to develop these reserves.  A significant amount of our proved undeveloped reserves that were reclassified to unproved remain economic at current prices, and we may report proved undeveloped reserves in future filings if we determine we have the financial capability to execute a development plan.  

The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are inherent uncertainties in estimating quantities of proved reserves including projecting the future rates of production and the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data, and engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of

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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.     

6.Earnings (loss) per share

The following table presents the basic and diluted earnings (loss) per share computations for the three and nine months endedSeptember 30, 2016 and 2015: 

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands, except per share data)	2016		2015			2016			2015
Basic net income (loss) per common share:
Net income (loss)	$	50,936	$	(354,519	)	$	(190,559	)	$	(1,126,786	)
Weighted average common shares outstanding	279,873		273,348			279,008			272,147
Net income (loss) per basic common share	$	0.18	$	(1.30	)	$	(0.68	)	$	(4.14	)
Diluted net income (loss) per common share:
Net income (loss)	$	50,936	$	(354,519	)	$	(190,559	)	$	(1,126,786	)
Weighted average common shares outstanding	279,873		273,348			279,008			272,147
Dilutive effect of:
Stock options	—		—			—			—
Restricted shares and restricted share units	1,172		—			—			—
Warrants	—		—			—			—
Weighted average common shares and common share equivalents outstanding	281,045		273,348			279,008			272,147
Net income (loss) per diluted common share	$	0.18	$	(1.30	)	$	(0.68	)	$	(4.14	)

Diluted net income (loss) per common share for the three and nine months endedSeptember 30, 2016 and 2015 is computed in the same manner as basic net income (loss) per share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which include stock options, restricted share units, restricted share awards and warrants, whether exercisable or not. The computation of diluted net income (loss) per share excluded 88,083,055 and 36,157,630 antidilutive share equivalents for the three months endedSeptember 30, 2016 and 2015, respectively, and 89,522,616 and 21,200,285 antidilutive share equivalents for the nine months endedSeptember 30, 2016 and 2015, respectively. Our antidilutive share equivalents for the three and nine months endedSeptember 30, 2016 included 80,000,000 warrants issued to Energy Strategic Advisory Services LLC ("ESAS"). See "Note 12. Related party transactions" for additional information on the warrants issued to ESAS. All of our outstanding warrants and stock options were out-of-the-money and considered antidilutive during the three months ended September 30, 2016.

7.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 instruments consists of non-cash income or expense due to changes in the fair value. 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.

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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)	September 30, 2016			December 31, 2015
Derivative financial instruments - Current assets	$	5,952		$	39,499
Derivative financial instruments - Long-term assets	1,455			6,109
Derivative financial instruments - Current liabilities	(10,353		)	(16		)
Derivative financial instruments - Long-term liabilities	(1,189		)	—
Net derivative financial instruments	$	(4,135	)	$	45,592

Effect of Derivative Financial Instruments

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2016		2015		2016			2015
Gain (loss) on derivative financial instruments	$	8,209	$	37,348	$	(11,632	)	$	54,427

Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from, or cash disbursements to, our derivative contract counterparties. Changes in the fair value of our derivative financial instrument contracts, which include both cash settlements and non-cash changes in fair value, are included in earnings with a corresponding increase or decrease in the Condensed Consolidated Balance Sheets fair value amounts.

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.

Swaptions:These contracts give our trading counterparties the right, but not the obligation, to enter into a swap contract for an agreed quantity of oil or natural gas from us at a certain time and fixed price in the future. The counterparty to our swaption contracts can choose to exercise its option in December 2016 to enter into 2017 swap contracts.

Collars: A collar is a combination of options including a sold call and a purchased put. These contracts allow us to participate in the upside of commodity prices to the ceiling of the call option and provide us with downside protection through the put option. If the market price is below the strike price of the purchased put at the time of settlement then the counterparty pays us the excess. If the market price is above the strike price of the sold call at 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 the EXCO Resources Credit Agreement 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. Our credit rating and financial condition may restrict our ability to enter into certain types of derivative financial instruments and limit the maturity of the contracts with counterparties. Our derivative contracts also contain rights that could result in the early termination of our derivative contracts and cash payments to our counterparties due to an event of default under the EXCO Resources Credit Agreement.

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The following table presents the volumes and fair value of our oil and natural gas derivative financial instruments as of September 30, 2016:

(dollars in thousands, except prices)	Volume Bbtu/Mbbl	Weighted average strike price per Mmbtu/Bbl		Fair value at September 30, 2016
Natural gas:
Swaps:
Remainder of 2016	14,260	$	2.88	$	(1,610	)
2017	23,700	2.99		(2,440		)
2018	3,650	3.15		819
Swaptions:
2017	7,300	2.76		(2,743		)
Collars:
2017	10,950			(420		)
Sold call		3.28
Purchased put		2.87
Total natural gas				$	(6,394	)
Oil:
Swaps:
Remainder of 2016	276	$	58.61	$	2,542
2017	183	50.00		(283		)
Total oil				$	2,259
Total oil and natural gas derivative financial instruments				$	(4,135	)

At December 31, 2015, we had outstanding swap contracts covering 49,370 Bbtu of natural gas and 915 Mbbls of oil.

At September 30, 2016, the average forward NYMEX WTI oil prices per Bbl for the remainder of 2016 and calendar year 2017 were $48.53 and $51.30, respectively, and the average forward NYMEX HH natural gas prices per Mmbtu for the remainder of 2016 and calendar years 2017 and 2018 were $3.02, $3.09 and $2.91, respectively.

Our derivative financial instruments covered approximately 60% and 69% of production volumes for the three months endedSeptember 30, 2016 and 2015, respectively, and 55% and 66% of production volumes for the nine months endedSeptember 30, 2016 and 2015, respectively.

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8.Debt

The carrying value of our total debt is summarized as follows:

(in thousands)	September 30, 2016			December 31, 2015
EXCO Resources Credit Agreement	$	214,592		$	67,492
Exchange Term Loan	603,116			641,172
Fairfax Term Loan	300,000			300,000
2018 Notes	131,576			158,015
Unamortized discount on 2018 Notes	(589		)	(932		)
2022 Notes	70,169			222,826
Deferred financing costs, net	(12,796		)	(18,294		)
Total debt	1,306,068			1,370,279
Less amounts due within one year	50,000			50,000
Total debt due after one year	$	1,256,068		$	1,320,279

	September 30, 2016
(in thousands)	Carrying value			Deferred reduction in carrying value			Unamortized discount/deferred financing costs		Principal balance
EXCO Resources Credit Agreement	$	214,592		$	—		$	—	$	214,592
Exchange Term Loan	603,116			(203,116		)	—		400,000
Fairfax Term Loan	300,000			—			—		300,000
2018 Notes	130,987			—			589		131,576
2022 Notes	70,169			—			—		70,169
Deferred financing costs, net	(12,796		)	—			12,796		—
Total debt	$	1,306,068		$	(203,116	)	$	13,385	$	1,116,337

Terms and conditions of our debt obligations are discussed below.

Tender Offer and open market repurchases

On August 24, 2016, we completed a cash tender offer for our outstanding senior unsecured notes ("Tender Offer") that resulted in the repurchase of an aggregate of $101.3 million in principal amount of the 2022 Notes for an aggregate purchase price of $40.0 million. Holders of the 2022 Notes that were accepted for payment in the Tender Offer also received accumulated and unpaid interest. The Tender Offer was funded with the borrowings under the EXCO Resources Credit Agreement.

For the nine months endedSeptember 30, 2016, we repurchased an aggregate of $26.4 million and $152.7 million in principal amount of the 2018 Notes and 2022 Notes, respectively, with an aggregate of $53.3 million in cash through the Tender Offer and open market repurchases. These repurchases resulted in net gains on extinguishment of debt of $57.4 million and $119.4 millionfor the three and nine months endedSeptember 30, 2016, respectively.

EXCO Resources Credit Agreement

As of September 30, 2016, we had $214.6 million of outstanding indebtedness and a borrowing base of $325.0 million under the EXCO Resources Credit Agreement. On September 1, 2016, the lenders under the EXCO Resources Credit Agreement postponed the scheduled redetermination of the borrowing base from September 1, 2016 to November 1, 2016 at our request. We are currently working with the lenders to amend the EXCO Resources Credit Agreement and the redetermination of the borrowing base is still in progress. There is no assurance that we will be able to amend the EXCO Resources Credit Agreement and our lenders have discretion in the timing and amount during the redetermination process. In connection with the postponed redetermination, we may not request borrowings from the lenders under the EXCO Resources Credit Agreement that would result in their aggregate exposure to exceed $300.0 million, including letters of credit, until the effective date of the postponed redetermination. Therefore, the Company's available borrowing capacity was $75.4 million as of September 30, 2016.

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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 London Interbank Offered Rate ("LIBOR") plus 225 bps to 325 bps (or alternate base rate ("ABR") plus 125 bps to 225 bps), depending on our borrowing base usage. On September 30, 2016, our interest rate was approximately 3.5%.

As of September 30, 2016, we were in compliance with the financial covenants (defined in the EXCO Resources Credit Agreement), which required that we:

• maintain a Consolidated Current Ratio of at least 1.0 to 1.0 as of the end of any fiscal quarter. The consolidated current assets utilized in this ratio include unused commitments under the EXCO Resources Credit Agreement. As of September 30, 2016, the unused commitments were based on the Company's borrowing base of $325.0 million;

• maintain a ratio of consolidated EBITDAX to consolidated interest expense (“Interest Coverage Ratio”) of at least 1.25 to 1.0 as of the end of any fiscal quarter. The consolidated interest expense utilized in the Interest Coverage Ratio is calculated in accordance with GAAP; therefore, this excludes cash payments under the terms of the Exchange Term Loan (as defined below), whether designated as interest or as principal amount, that reduce the carrying amount and are not recognized as interest expense; and

• not permit a Senior Secured Indebtedness Ratio to be greater than 2.5 to 1.0 as of the end of any fiscal quarter. Senior secured indebtedness utilized in the Senior Secured Indebtedness Ratio excludes the Second Lien Term Loans and any other secured indebtedness subordinated to the EXCO Resources Credit Agreement.

Our liquidity and ability to maintain compliance with debt covenants have been negatively impacted by the prolonged depressed oil and natural gas price environment, levels of indebtedness, and gathering, transportation and certain other commercial contracts. Based on our current estimates and expectations, we do not believe we will be able to comply with all of the covenants under the EXCO Resources Credit Agreement for the twelve-month period following the date of these unaudited Condensed Consolidated Financial Statements. See "Note 1. Organization and basis of presentation" for further discussion on this matter.

Second Lien Term Loans

On October 26, 2015, we closed a 12.5% senior secured second lien term loan with certain affiliates of Fairfax Financial Holdings Limited ("Fairfax") in the aggregate principal amount of $300.0 million ("Fairfax Term Loan"). We also closed a 12.5% senior secured second lien term loan with certain unsecured noteholders in the aggregate principal amount of $291.3 million on October 26, 2015 and $108.7 million on November 4, 2015 (“Exchange Term Loan"). The proceeds from the Exchange Term Loan were used to repurchase a portion of the outstanding 2018 Notes and 2022 Notes in exchange for the holders of such notes agreeing to act as lenders in connection with the Exchange Term Loan. The exchange was accounted for as a troubled debt restructuring pursuant to FASB ASC 470-60, Troubled Debt Restructuring by Debtors. The future undiscounted cash flows from the Exchange Term Loan through its maturity were less than the carrying amounts of the retired 2018 Notes and 2022 Notes. As a result, the carrying amount of the Exchange Term Loan is equal to the total undiscounted future cash payments, including interest and principal.  All cash payments under the terms of the Exchange Term Loan, whether designated as interest or as principal amount, will reduce the carrying amount and no interest expense will be recognized. As such, our reported interest expense will be less than the contractual payments throughout the term of the Exchange Term Loan. 

The Second Lien Term Loans mature on October 26, 2020 with interest payable on the last day in each calendar quarter. The Second Lien Term Loans are guaranteed by substantially all of EXCO’s subsidiaries, with the exception of certain non-guarantor subsidiaries and our jointly held equity investments with BG Group, and are secured by second-priority liens on substantially all of EXCO’s assets securing the indebtedness under the EXCO Resources Credit Agreement. The Second Lien Term Loans rank (i) junior to the debt under the EXCO Resources Credit Agreement and any other priority lien obligations, (ii) pari passu to one another and (iii) effectively senior to all of our existing and future unsecured senior indebtedness, including the 2018 Notes and the 2022 Notes, to the extent of the value of collateral.

The agreements governing the Second Lien Term Loans contain covenants that, subject to certain exceptions, limit our ability and the ability of our restricted subsidiaries to, among other things:

• pay dividends or make other distributions or redeem or repurchase our common shares;

• prepay, redeem or repurchase certain debt;

• enter into agreements restricting the subsidiary guarantors’ ability to pay dividends to us or another subsidiary guarantor, make loans or advances to us or transfer assets to us;

• engage in asset sales or substantially alter the business that the we conduct, unless the proceeds are utilized to prepay the Second Lien Term Loans, reduce priority lien indebtedness, or reinvest in the acquisition or development of oil and gas properties;

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• enter into transactions with affiliates;

• consolidate, merge or dispose of assets;

• incur liens; and

• enter into sale/leaseback transactions.

In addition, the term loan agreement governing the Exchange Term Loan prohibits us from incurring, among other things and subject to certain exceptions:

• debt under credit facilities, as defined in the term loan credit agreement governing the Exchange Term Loan, in excess of the greatest of (i) $375.0 million plus an amount equal to six and two-thirds percent of the aggregate principal amount of our outstanding indebtedness under the EXCO Resources Credit Agreement for over-advances to protect collateral, (ii) the borrowing base under the EXCO Resources Credit Agreement and (iii) 30% of modified adjusted consolidated net tangible assets (as defined in the agreement);

• second lien debt in excess of $700.0 million; and

• unsecured debt where on the date of such incurrence or after giving effect to such incurrence, our consolidated coverage ratio (as defined in the agreement) is or would be less than 2.25 to 1.0.

The term loan agreement governing the Fairfax Term Loan prohibits us from incurring, among other things and subject to certain exceptions:

• debt under credit facilities, as defined in the term loan credit agreement governing the Fairfax Term Loan, in excess of $375.0 million plus an amount equal to six and two-thirds percent of the aggregate principal amount of our outstanding indebtedness under the EXCO Resources Credit Agreement for over-advances to protect collateral, provided that such indebtedness may not exceed $500.0 million, unless we obtain consent from the administrative agent;

• second lien debt, other than the Exchange Term Loan, in an amount to be agreed upon with the administrative agent;

• junior lien debt, unless such debt is being used to refinance the 2018 Notes or the 2022 Notes or the terms and conditions of such junior lien debt are approved by the administrative agent; and

• unsecured debt, unless we obtain consent from the administrative agent.

In addition, under the term loan credit agreement governing the Fairfax Term Loan, a change of control constitutes an event of default, which, subject to certain limitations, may allow the Fairfax Term Loan lenders to declare the Fairfax Term Loan to be due and payable, in whole or in part, including accrued but unpaid interest thereon, plus an amount equal to all interest payments that would have accrued through the Fairfax Term Loan maturity date. Under the term loan credit agreement governing the Exchange Term Loan, in the event of a change of control EXCO is required to offer to repurchase the Exchange Term Loan at 101% of the face value of the Exchange Term Loan.

In connection with the Second Lien Term Loans, on October 26, 2015, EXCO entered into an intercreditor agreement governing the relationship between EXCO’s lenders and the holders of any other lien obligations that EXCO may issue in the future and a collateral trust agreement governing the administration and maintenance of the collateral securing the Second Lien Term Loans.

2018 Notes

The 2018 Notes are guaranteed on a senior unsecured basis by a majority of EXCO’s subsidiaries, with the exception of certain non-guarantor subsidiaries and our jointly held equity investments with BG Group. Our equity investments, other than OPCO, have been designated as unrestricted subsidiaries under the indenture governing the 2018 Notes.

In the fourth quarter of 2015, EXCO repurchased an aggregate $551.2 million of the 2018 Notes in exchange for certain holders of the 2018 Notes becoming lenders under the Exchange Term Loan. Additionally, as of September 30, 2016, we had repurchased a total of $67.2 million in principal amount of the 2018 Notes for an aggregate of $18.8 million in a series of open market repurchases. As a result of the repurchases, the aggregate principal amount of outstanding 2018 Notes was reduced to $131.6 million as of September 30, 2016. Interest accrues at 7.5% per annum and is payable semi-annually in arrears on March 15 and September 15 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 stock;

• pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;

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• 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

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. In the fourth quarter of 2015, EXCO repurchased an aggregate $277.2 million in principal amount of the 2022 Notes in exchange for certain holders of the 2022 Notes becoming lenders under the Exchange Term Loan. On August 24, 2016, we completed the Tender Offer that resulted in the repurchases of an aggregate of $101.3 million in principal amount of the 2022 Notes for an aggregate purchase price of $40.0 million. As of September 30, 2016, through the Tender Offer and a series of open market repurchases, we had repurchased a total of $152.7 million in principal amount of the 2022 Notes for an aggregate of $46.5 million. As a result of the repurchases, the aggregate principal amount of outstanding 2022 Notes was reduced to $70.2 million as of September 30, 2016.

In conjunction with the Tender Offer, we solicited consents from the registered holders of the 2022 Notes to amend certain terms of the indenture governing the 2022 Notes. Following the consummation of the consent solicitation, we entered into a supplemental indenture governing the 2022 Notes to amend the definition of “Credit Facilities” to include debt securities as a permitted form of additional secured indebtedness, in addition to the term loans and other credit facilities currently permitted.

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.

9.Commitments and contingencies

Settlement of Participation Agreement litigation

In July 2013, we entered into a participation agreement with a joint venture partner for the development of certain assets in the Eagle Ford shale ("Participation Agreement"). As described in "Item 3. Legal Proceedings" in our 2015 Form 10-K, we were in a dispute subject to litigation over the offer and the acceptance process with our joint venture partner.

On July 25, 2016, we settled the litigation with our joint venture partner, and the litigation was thereafter dismissed after a final judgment order was entered in response to the parties’ joint motion to dismiss the case with prejudice. Among other things, the settlement provided a full release for any claims, rights, demands, damages and causes of action that either party has asserted or could have asserted for any breach of the Participation Agreement. As part of the settlement, the parties amended and restated the Participation Agreement to (i) eliminate our requirement to offer to purchase our joint venture partner's interests in certain wells each quarter, (ii) eliminate our requirement to convey a portion of our working interest to our joint venture partner upon commencing development of future locations, (iii) terminate the area of mutual interest, which required either party acquiring an interest in non-producing acreage included in certain areas to provide notice of the acquisition to the non-acquiring party and allowed the non-acquiring party to acquire a proportionate share in such acquired interest, (iv) provide that EXCO transfer to its joint venture partner a portion of its interests in certain producing wells and certain undeveloped locations in South Texas (“Transferred Interests”), effective May 1, 2016 and (v) modify or eliminate certain other provisions.

We recorded a loss in "Other operating items" in the Condensed Consolidated Statements of Operations, and a corresponding credit to the "Proved developed and undeveloped oil and natural gas properties" in our Condensed Consolidated Balance Sheet during the nine months ended September 30, 2016. The fair value of the Transferred Interests was $23.2 million as of July 25, 2016 based on a discounted cash flow model of the estimated reserves using NYMEX forward strip prices. See

18

"Note 10. Fair value measurements" for additional information. The net production from the Transferred Interests was approximately 350 Bbls of oil per day during June 2016.

Natural gas sales and firm transportation contract litigation

During the third quarter of 2016, we terminated our sales and transportation contracts with Enterprise Products Operating LLC (“Enterprise”) and Acadian Gas Pipeline System (“Acadian”), respectively. We transported natural gas produced from our operated wells in North Louisiana through Acadian, and Enterprise was a purchaser of certain volumes of our natural gas, until we terminated the contracts. Enterprise and Acadian are part of the corporate family of Enterprise Products Partners L.P. (“EPD”). Acadian is an indirect, wholly-owned subsidiary of EPD that owns and operates the Acadian natural gas pipeline system. The agreement with Acadian provided for the firm transportation of 150,000 Mmbtu/day and 175,000 Mmbtu/day of natural gas at reservation fees of $0.25 and $0.20, respectively. In addition, the sales contract with Enterprise contemplated that we could, subject to certain limitations and exclusions, sell 75,000 Mmbtu/day of natural gas at a $0.25 reduction from market index prices. The primary term for these contracts had been through October 31, 2025. The fees described represent our gross commitments and a portion of these costs is allocated to working interest and other owners. The Acadian firm transportation agreement is accounted for as gathering and transportation expenses and the Enterprise sales contract is accounted for as a reduction in the total sales price within revenues.

Under the parties’ sales and transportation agreements, Enterprise owed us for July 2016 natural gas sales, and we owed Acadian for July 2016 transportation fees. The amount owed to us by Enterprise exceeded the amount owed by us to Acadian. We notified Enterprise in writing of its failure to pay and gave Enterprise opportunity to cure. When Enterprise failed to cure, we gave written notice to Enterprise and Acadian that we were terminating the sales and transportation agreements. Enterprise and Acadian subsequently filed an action in Harris County, Texas, against us alleging that we could not terminate the parties’ agreements despite Enterprise's uncured payment default under the natural gas sales agreement, and further alleged that we were in breach of the firm transportation agreements. On October 17, 2016, we filed a counterclaim asserting that Enterprise was the breaching party because it improperly withheld payment for natural gas we delivered to it and the amounts owed by Enterprise exceeded the amounts owed by us to Acadian. We are also seeking a declaration that we properly terminated the contracts with Enterprise and Acadian. We cannot currently estimate or predict the outcome of the litigation but we plan to vigorously defend our right to terminate the contracts and to seek the amounts owed to us for delivered natural gas.

We are no longer selling natural gas under the Enterprise sales contract or transporting natural gas under the Acadian firm transportation contract effective as of the termination date. The Company is accounting for these contracts in accordance with FASB ASC 450 ("ASC 450"), Contingencies, which states a contingency that might result in a gain should not be reflected until it is realized or realizable. There is a rebuttable presumption that a claim subject to litigation does not meet the criteria to be realized or realizable; therefore, the termination of these contracts will not be reflected in our financial results until the litigation is resolved. Upon resolution of the litigation, we will adjust the previously recognized amounts to reflect the outcome of the litigation. As of September 30, 2016, we recorded a $6.4 million receivable related to the net amounts owed by Enterprise prior to the termination of the contracts and an accrual of $2.1 million for costs subsequent to the termination of the contract in accordance with the guidance related to contingencies in ASC 450.

10.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.

19

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 ratings, futures markets and forward curves, and readily available buyers or sellers. During the nine months endedSeptember 30, 2016 and 2015 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 September 30, 2016 and December 31, 2015.

	September 30, 2016
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	(4,135	)	$	—	$	(4,135	)
	December 31, 2015
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	45,592		$	—	$	45,592

We evaluate derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them on a gross basis in our Condensed Consolidated Balance Sheets. Net 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 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, collars and swaption contracts, is discussed below.

Oil derivatives. Our oil derivatives are swap contracts for notional barrels of oil at fixed 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, and (iii) the applicable credit-adjusted risk-free rate curve, as described above.

Natural gas derivatives. Our natural gas derivatives are swap, collar and swaption contracts for notional Mmbtus of natural gas at posted price indexes, including NYMEX HH swap, option and swaption 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 natural gas swaps, (iii) the applicable credit-adjusted risk-free rate curve, as described above, and (iv) the implied rates of volatility inherent in the option and swaption contracts. The implied rates of volatility were determined based on the average of historical HH natural gas prices.

See further details on the fair value of our derivative financial instruments in “Note 7. Derivative financial instruments”.

Fair value of other financial instruments

Our financial instruments include cash and cash equivalents, accounts receivable and payable and accrued liabilities.  The carrying amount of these instruments approximates fair value because of their short-term nature.

The carrying values of our borrowings under the EXCO Resources Credit Agreement approximate fair value, as these are subject to short-term floating interest rates that approximate the rates available to us for those periods.

The estimated fair values of our 2018 Notes, 2022 Notes, Exchange Term Loan and Fairfax Term Loan are presented below. The estimated fair values of the 2018 Notes and 2022 Notes have been calculated based on quoted prices in active markets. The estimated fair values of the Exchange Term Loan and the Fairfax Term Loan have been calculated based on quoted prices obtained from third-party pricing sources and are classified as Level 2.

20

	September 30, 2016
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	60,438	$	—	$	—	$	60,438
2022 Notes	27,366		—		—		27,366
Exchange Term Loan	—		263,500		—		263,500
Fairfax Term Loan	—		197,625		—		197,625
	December 31, 2015
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	43,170	$	—	$	—	$	43,170
2022 Notes	48,376		—		—		48,376
Exchange Term Loan	—		278,000		—		278,000
Fairfax Term Loan	—		208,500		—		208,500

Other fair value measurements

During the nine months endedSeptember 30, 2016, we impaired $4.9 million of our investment in a midstream company in the East Texas and North Louisiana regions that we account for under the cost method of accounting. The impairment was recorded to reduce the carrying value to the fair value and is considered to be Level 3 within the fair value hierarchy. The estimated fair value of our cost method investment was determined based on trading metrics of comparable transactions.

As discussed in "Note 9. Commitments and contingencies", we recorded a $23.2 million loss in "Other operating items" in our Condensed Consolidated Statements of Operations for the nine months ended September 30, 2016 and a corresponding credit to our "Proved developed and undeveloped oil and natural gas properties" in our balance sheet related to the settlement of litigation with a joint venture partner in the Eagle Ford shale. The fair market value of the properties transferred pursuant to the settlement was determined using 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. The fair value measurements utilized included significant unobservable inputs that are considered to be Level 3 within the fair value hierarchy. These unobservable inputs include management's estimates of reserve quantities, commodity prices, operating costs, development costs, discount factors and other risk factors applied to the future cash flows.

11.Income taxes

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. We have accumulated financial deferred tax assets primarily due to losses arising from impairments to the carrying value of our oil and natural gas properties that are subject to valuation allowances. Our valuation allowances increased $69.4 million for the nine months endedSeptember 30, 2016. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $1.4 billion that have fully offset our net deferred tax assets as of September 30, 2016. The valuation allowances will continue to be recognized until the realization of future deferred tax benefits are more likely than not to become utilized. The valuation allowances do not impact future utilization of the underlying tax attributes.

12.Related party transactions

OPCO

OPCO serves as the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis. We did not advance any funds to OPCO during three and nine months endedSeptember 30, 2016 or 2015. 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 three and nine months endedSeptember 30, 2016 and 2015, these transactions included the following:

21

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2016		2015		2016		2015
Amounts received from OPCO	$	3,824	$	7,281	$	12,586	$	23,847

As of September 30, 2016 and December 31, 2015, the amounts owed were as follows:

(in thousands)	September 30, 2016		December 31, 2015
Amounts due to EXCO (1)	$	932	$	1,733
Amounts due from EXCO (1)	12,903		10,410

(1) Advances to OPCO are recorded in "Other current assets" in our Condensed Consolidated Balance Sheets. Any amounts we owe to OPCO are netted against the advance until the advances are utilized. If the advances are fully utilized, we record amounts owed in "Accounts payable and accrued liabilities" in our Condensed Consolidated Balance Sheets.

ESAS

On September 8, 2015, we closed the services and investment agreement with ESAS, a wholly owned subsidiary of Bluescape Resources Company LLC ("Bluescape"). At the closing, C. John Wilder, Executive Chairman of Bluescape, was appointed as a member of our Board of Directors and as Executive Chairman of the Board of Directors. As part of the agreement, ESAS completed its required purchase of EXCO's common shares as of December 31, 2015 and is currently the beneficial owner of approximately 6.5% of our outstanding common shares.

As consideration for the services provided under the agreement, EXCO pays ESAS a monthly fee of $300,000 and an annual incentive payment of up to $2.4 million per year that is based on EXCO’s common share price achieving certain performance hurdles as compared to a peer group. The monthly fees were held in escrow until one year following the closing of the agreement and reported as "Restricted cash" on our Condensed Consolidated Balance Sheets. In September 2016, we made a cash payment to ESAS of $7.2 million, which consisted of (i) the monthly fees previously held in escrow and (ii) a $2.4 million annual incentive payment as a result of EXCO achieving a performance rank above the 75th percentile of the peer group. Our accrual totaled $0.9 million and $4.5 million at September 30, 2016 and December 31, 2015, respectively, for the services performed under the services and investment agreement, and is recorded in "Accounts payable and accrued liabilities" in our Condensed Consolidated Balance Sheets. The amount at September 30, 2016 includes an accrual for the annual incentive payment of $0.6 million as a result of EXCO's performance rank.

As an additional performance incentive under the services and investment agreement, EXCO issued warrants to ESAS in four tranches to purchase an aggregate of 80,000,000 common shares. These warrants may become exercisable in the future if our common shares achieve certain performance metrics compared to a peer group as of March 31, 2019. The measurement of the warrants is accounted for in accordance with ASC Topic 505-50, Equity-Based Payments to Non-Employees, which requires the warrants to be re-measured each interim reporting period until the completion of the services on March 31, 2019 and an adjustment is recorded in the statement of operations within equity-based compensation expense. For the three and nine months endedSeptember 30, 2016, we recognized equity-based compensation related to the warrants of $0.9 million and $11.8 million, respectively, and $0.2 million for the three and nine months ended September 30, 2015.

In the first quarter of 2016, ESAS entered into an agreement with an unaffiliated lender under the Exchange Term Loan, pursuant to which the lender will make periodic payments to ESAS or receive periodic payments from ESAS based on changes in the market value of the Exchange Term Loan, and the lender will make periodic payments to ESAS based on the interest rate of the Exchange Term Loan. As of September 30, 2016, the agreement effectively provided ESAS with the economic consequences of ownership of approximately $47.9 million in principal amount of the Exchange Term Loan without direct ownership of, or consent rights with respect to, the Exchange Term Loan.

As described above, ESAS is a wholly owned subsidiary of Bluescape, and C. John Wilder, a member of our Board of Directors, is Bluescape’s Executive Chairman. As Bluescape’s Executive Chairman, Mr. Wilder has the power to direct the affairs of Bluescape and, indirectly, ESAS, and may be deemed to share ESAS’s interest in the Exchange Term Loan and our common shares.

See our 2015 Form 10-K for additional disclosures related to the services and investment agreement and the related warrants.

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Fairfax

Hamblin Watsa Investment Counsel Ltd. (“Hamblin Watsa”), a wholly owned subsidiary of Fairfax, is the administrative agent of the Fairfax Term Loan and certain affiliates of Fairfax are lenders under the Fairfax Term Loan and a portion of the Exchange Term Loan. As of September 30, 2016, affiliates of Fairfax were the record holders of approximately $112.1 million in principal amount of the Exchange Term Loan. Samuel A. Mitchell, a member of our Board of Directors, is a Managing Director of Hamblin Watsa and a member of Hamblin Watsa’s investment committee, which consists of seven members that manage the investment portfolio of Fairfax. Based on filings with the SEC, Fairfax is the beneficial owner of approximately 9.0% of our outstanding common shares. See “Note 8. Debt” for additional information.

13.Condensed consolidating financial statements

As of September 30, 2016, the majority of EXCO’s subsidiaries were guarantors under the EXCO Resources Credit Agreement and the indentures governing the 2018 Notes and 2022 Notes and the agreements governing the Second Lien Term Loans. All of our unrestricted subsidiaries under the Second Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes are considered non-guarantor subsidiaries.

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The 2018 Notes, 2022 Notes and the Second Lien Term Loans, which were issued by EXCO Resources, Inc., are jointly and severally guaranteed by substantially all of our subsidiaries (referred to as Guarantor Subsidiaries). For purposes of this footnote, EXCO Resources, Inc. is referred to as Resources to distinguish it from the Guarantor Subsidiaries. Each of the Guarantor Subsidiaries is a 100% owned subsidiary of Resources and the guarantees are unconditional as they relate to the assets of the Guarantor Subsidiaries.

The following financial information presents consolidating financial statements, which include:

• Resources;

• the Guarantor Subsidiaries;

• the Non-Guarantor Subsidiaries;

• elimination entries necessary to consolidate Resources, the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries; and

• EXCO on a consolidated basis.

Investments in subsidiaries are accounted for using the equity method of accounting for the disclosures within this footnote. The financial information for the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries is presented on a combined basis. The elimination entries primarily eliminate investments in subsidiaries and intercompany balances and transactions.

23

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

September 30, 2016

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	9,754		$	(6,220	)	$	—	$	—		$	3,534
Restricted cash	—			18,434			—		—			18,434
Other current assets	13,233			75,608			—		—			88,841
Total current assets	22,987			87,822			—		—			110,809
Equity investments	—			—			31,973		—			31,973
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	—			93,511			—		—			93,511
Proved developed and undeveloped oil and natural gas properties	331,326			2,615,315			—		—			2,946,641
Accumulated depletion	(330,776		)	(2,359,835		)	—		—			(2,690,611		)
Oil and natural gas properties, net	550			348,991			—		—			349,541
Other property and equipment, net	608			23,450			—		—			24,058
Investments in and advances to affiliates, net	452,896			—			—		(452,896		)	—
Deferred financing costs, net	5,000			—			—		—			5,000
Derivative financial instruments	1,455			—			—		—			1,455
Goodwill	13,293			149,862			—		—			163,155
Total assets	$	496,789		$	610,125		$	31,973	$	(452,896	)	$	685,991
Liabilities and shareholders' equity
Current liabilities	$	74,818		$	167,105		$	—	$	—		$	241,923
Long-term debt	1,256,068			—			—		—			1,256,068
Other long-term liabilities	3,493			22,097			—		—			25,590
Payable to parent	—			2,360,227			—		(2,360,227		)	—
Total shareholders' equity	(837,590		)	(1,939,304		)	31,973		1,907,331			(837,590		)
Total liabilities and shareholders' equity	$	496,789		$	610,125		$	31,973	$	(452,896	)	$	685,991

24

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2015

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	34,296		$	(22,049	)	$	—	$	—		$	12,247
Restricted cash	2,100			19,120			—		—			21,220
Other current assets	51,133			65,201			—		—			116,334
Total current assets	87,529			62,272			—		—			149,801
Equity investments	—			—			40,797		—			40,797
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	—			115,377			—		—			115,377
Proved developed and undeveloped oil and natural gas properties	330,775			2,739,655			—		—			3,070,430
Accumulated depletion	(330,775		)	(2,296,988		)	—		—			(2,627,763		)
Oil and natural gas properties, net	—			558,044			—		—			558,044
Other property and equipment, net	749			27,063			—		—			27,812
Investments in and advances to affiliates, net	616,940			—			—		(616,940		)	—
Deferred financing costs, net	8,408			—			—		—			8,408
Derivative financial instruments	6,109			—			—		—			6,109
Goodwill	13,293			149,862			—		—			163,155
Total assets	$	733,028		$	797,241		$	40,797	$	(616,940	)	$	954,126
Liabilities and shareholders' equity
Current liabilities	$	74,472		$	178,447		$	—	$	—		$	252,919
Long-term debt	1,320,279			—			—		—			1,320,279
Other long-term liabilities	600			42,651			—		—			43,251
Payable to parent	—			2,276,594			—		(2,276,594		)	—
Total shareholders' equity	(662,323		)	(1,700,451		)	40,797		1,659,654			(662,323		)
Total liabilities and shareholders' equity	$	733,028		$	797,241		$	40,797	$	(616,940	)	$	954,126

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months endedSeptember 30, 2016

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	70,862		$	—		$	—	$	70,862
Purchased natural gas and marketing	—			6,324			—			—		6,324
Total revenues	—			77,186			—			—		77,186
Costs and expenses:
Oil and natural gas production	—			12,608			—			—		12,608
Gathering and transportation	—			27,979			—			—		27,979
Purchased natural gas	—			6,586			—			—		6,586
Depletion, depreciation and amortization	89			15,821			—			—		15,910
Impairment of oil and natural gas properties	—			—			—			—		—
Accretion of discount on asset retirement obligations	—			325			—			—		325
General and administrative	(4,395		)	15,141			—			—		10,746
Other operating items	—			(1,110		)	—			—		(1,110		)
Total costs and expenses	(4,306		)	77,350			—			—		73,044
Operating income (loss)	4,306			(164		)	—			—		4,142
Other income (expense):
Interest expense, net	(16,997		)	—			—					(16,997		)
Gain on derivative financial instruments	8,209			—			—					8,209
Gain on extinguishment of debt	57,421			—			—					57,421
Other income	4			8			—					12
Equity loss	—			—			(823		)			(823		)
Net loss from consolidated subsidiaries	(979		)	—			—			979		—
Total other income (expense)	47,658			8			(823		)	979		47,822
Income (loss) before income taxes	51,964			(156		)	(823		)	979		51,964
Income tax expense	1,028			—			—			—		1,028
Net income (loss)	$	50,936		$	(156	)	$	(823	)	$	979	$	50,936

26

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months endedSeptember 30, 2015

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	83,744		$	—		$	—	$	83,744
Purchased natural gas and marketing	—			6,773			—			—		6,773
Total revenues	—			90,517			—			—		90,517
Costs and expenses:
Oil and natural gas production	7			18,606			—			—		18,613
Gathering and transportation	—			23,743			—			—		23,743
Purchased natural gas	—			6,991			—			—		6,991
Depletion, depreciation and amortization	229			51,784			—			—		52,013
Impairment of oil and natural gas properties	1,372			338,021			—			—		339,393
Accretion of discount on asset retirement obligations	—			574			—			—		574
General and administrative	(2,345		)	15,738			—			—		13,393
Other operating items	(3		)	(225		)	—			—		(228		)
Total costs and expenses	(740		)	455,232			—			—		454,492
Operating income (loss)	740			(364,715		)	—			—		(363,975		)
Other income (expense):
Interest expense, net	(27,761		)	—			—			—		(27,761		)
Gain on derivative financial instruments	37,348			—			—			—		37,348
Other income	14			7			—			—		21
Equity loss	—			—			(152		)	—		(152		)
Net loss from consolidated subsidiaries	(364,860		)	—			—			364,860		—
Total other income (expense)	(355,259		)	7			(152		)	364,860		9,456
Loss before income taxes	(354,519		)	(364,708		)	(152		)	364,860		(354,519		)
Income tax expense	—			—			—			—		—
Net loss	$	(354,519	)	$	(364,708	)	$	(152	)	$	364,860	$	(354,519	)

27

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months endedSeptember 30, 2016

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	176,732		$	—		$	—	$	176,732
Purchased natural gas and marketing	—			15,335			—			—		15,335
Total revenues	—			192,067			—			—		192,067
Costs and expenses:
Oil and natural gas production	4			39,139			—			—		39,143
Gathering and transportation	—			79,828			—			—		79,828
Purchased natural gas	—			17,273			—			—		17,273
Depletion, depreciation and amortization	298			63,697			—			—		63,995
Impairment of oil and natural gas properties	838			159,975			—			—		160,813
Accretion of discount on asset retirement obligations	—			2,006			—			—		2,006
General and administrative	(6,062		)	44,688			—			—		38,626
Other operating items	(406		)	24,342			—			—		23,936
Total costs and expenses	(5,328		)	430,948			—			—		425,620
Operating income (loss)	5,328			(238,881		)	—			—		(233,553		)
Other income (expense):
Interest expense, net	(54,186		)	—			—			—		(54,186		)
Loss on derivative financial instruments	(11,632		)	—			—			—		(11,632		)
Gain on extinguishment of debt	119,374			—			—			—		119,374
Other income	9			28			—			—		37
Equity loss	—			—			(8,824		)	—		(8,824		)
Net loss from consolidated subsidiaries	(247,677		)	—			—			247,677		—
Total other income (expense)	(194,112		)	28			(8,824		)	247,677		44,769
Loss before income taxes	(188,784		)	(238,853		)	(8,824		)	247,677		(188,784		)
Income tax expense	1,775			—			—			—		1,775
Net loss	$	(190,559	)	$	(238,853	)	$	(8,824	)	$	247,677	$	(190,559	)

28

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months endedSeptember 30, 2015

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	4		$	264,143		$	—		$	—	$	264,147
Purchased natural gas and marketing	—			21,012			—			—		21,012
Total revenues	4			285,155			—			—		285,159
Costs and expenses:
Oil and natural gas production	30			58,123			—			—		58,153
Gathering and transportation	—			74,243			—			—		74,243
Purchased natural gas	—			21,571			—			—		21,571
Depletion, depreciation and amortization	753			175,407			—			—		176,160
Impairment of oil and natural gas properties	8,263			1,001,784			—			—		1,010,047
Accretion of discount on asset retirement obligations	4			1,694			—			—		1,698
General and administrative	(6,569		)	47,796			—			—		41,227
Other operating items	2,065			(947		)	—			—		1,118
Total costs and expenses	4,546			1,379,671			—			—		1,384,217
Operating loss	(4,542		)	(1,094,516		)	—			—		(1,099,058		)
Other income (expense):
Interest expense, net	(80,822		)	—			—			—		(80,822		)
Gain on derivative financial instruments	54,427			—			—			—		54,427
Other income	87			32			—			—		119
Equity loss	—			—			(1,452		)	—		(1,452		)
Net loss from consolidated subsidiaries	(1,095,936		)	—			—			1,095,936		—
Total other income (expense)	(1,122,244		)	32			(1,452		)	1,095,936		(27,728		)
Loss before income taxes	(1,126,786		)	(1,094,484		)	(1,452		)	1,095,936		(1,126,786		)
Income tax expense	—			—			—			—		—
Net loss	$	(1,126,786	)	$	(1,094,484	)	$	(1,452	)	$	1,095,936	$	(1,126,786	)

29

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months endedSeptember 30, 2016

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	9,152		$	(12,892	)	$	—	$	—	$	(3,740	)
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(1,250		)	(69,205		)	—		—		(70,455		)
Proceeds from disposition of property and equipment	10			11,232			—		—		11,242
Restricted cash	—			686			—		—		686
Net changes in advances to joint ventures	—			2,377			—		—		2,377
Equity investments and other	—			—			—		—		—
Advances/investments with affiliates	(83,631		)	83,631			—		—		—
Net cash provided by (used in) investing activities	(84,871		)	28,721			—		—		(56,150		)
Financing Activities:
Borrowings under EXCO Resources Credit Agreement	390,897			—			—		—		390,897
Repayments under EXCO Resources Credit Agreement	(243,797		)	—			—		—		(243,797		)
Payments on Exchange Term Loan	(38,056		)	—			—		—		(38,056		)
Repurchases of senior unsecured notes	(53,298		)	—			—		—		(53,298		)
Deferred financing costs and other	(4,569		)	—			—		—		(4,569		)
Net cash provided by financing activities	51,177			—			—		—		51,177
Net increase (decrease) in cash	(24,542		)	15,829			—		—		(8,713		)
Cash at beginning of period	34,296			(22,049		)	—		—		12,247
Cash at end of period	$	9,754		$	(6,220	)	$	—	$	—	$	3,534

30

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months endedSeptember 30, 2015

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	27,860		$	98,996		$	—	$	—	$	126,856
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(1,784		)	(275,532		)	—		—		(277,316		)
Proceeds from disposition of property and equipment	686			6,711			—		—		7,397
Restricted cash	—			4,016			—		—		4,016
Net changes in advances to joint ventures	—			8,594			—		—		8,594
Equity investments and other	—			1,455			—		—		1,455
Advances/investments with affiliates	(181,813		)	181,813			—		—		—
Net cash used in investing activities	(182,911		)	(72,943		)	—		—		(255,854		)
Financing Activities:
Borrowings under EXCO Resources Credit Agreement	97,500			—			—		—		97,500
Proceeds from issuance of common shares, net	9,829			—			—		—		9,829
Deferred financing costs and other	(4,125		)	—			—		—		(4,125		)
Net cash provided by financing activities	103,204			—			—		—		103,204
Net increase (decrease) in cash	(51,847		)	26,053			—		—		(25,794		)
Cash at beginning of period	86,837			(40,532		)	—		—		46,305
Cash at end of period	$	34,990		$	(14,479	)	$	—	$	—	$	20,511

31

Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” are to EXCO Resources, Inc. and its consolidated subsidiaries.

Forward-looking statements

This Quarterly Report on Form 10-Q contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933, as amended ("Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended ("Exchange Act"). These forward-looking statements relate to, among other things, the following:

• our future financial and operating performance and results;

• our business strategy;

• market prices;

• our future use of derivative financial instruments; and

• our plans and forecasts.

We have based these forward-looking statements on our current assumptions, expectations and projections about future events. We use the words “may,” “expect,” “anticipate,” “estimate,” “believe,” “continue,” “intend,” “plan,” “potential,” “project,” “budget” and other similar words to identify forward-looking statements. The statements that contain these words should be read carefully because they discuss future expectations, contain projections of results of operations or our financial condition and/or state other “forward-looking” information. We do not undertake any obligation to update or revise any forward-looking statements, except as required by applicable securities laws. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Quarterly Report on Form 10-Q, including, but not limited to:

• fluctuations in the prices of oil and natural gas;

• the availability of oil and natural gas;

• future capital requirements and availability of financing, including reductions to our borrowing base and limitations on our ability to incur certain types of indebtedness under our debt agreements;

• our ability to meet our current and future debt service obligations, including our ability to maintain compliance with our debt covenants;

• disruption of credit and capital markets and the ability of financial institutions to honor their commitments;

• estimates of reserves and economic assumptions, including estimates related to acquisitions and dispositions of oil and natural gas properties;

• geological concentration of our reserves;

• risks associated with drilling and operating wells;

• exploratory risks, including those related to our activities in shale formations;

• discovery, acquisition, development and replacement of oil and natural gas reserves;

• cash flow and liquidity;

• timing and amount of future production of oil and natural gas;

• availability of drilling and production equipment;

• availability of water and other materials for drilling and completion activities;

• marketing of oil and natural gas;

• political and economic conditions and events in oil-producing and natural gas-producing countries;

• title to our properties;

• litigation;

• competition;

• our ability to attract and retain key personnel;

• general economic conditions, including costs associated with drilling and operations of our properties;

• our ability to comply with the listing requirements of, and maintain the listing of our common shares on, the New York Stock Exchange ("NYSE");

• environmental or other governmental regulations, including legislation to reduce emissions of greenhouse gases, legislation of derivative financial instruments, regulation of hydraulic fracture stimulation and elimination of income tax incentives available to our industry;

• receipt and collectability of amounts owed to us by purchasers of our production and counterparties to our derivative financial instruments;

• decisions whether or not to enter into derivative financial instruments;

• potential acts of terrorism;

32

• our ability to manage joint ventures with third parties, including the resolution of any material disagreements and our partners’ ability to satisfy obligations under these arrangements;

• actions of third party co-owners of interests in properties in which we also own an interest;

• fluctuations in interest rates;

• our ability to effectively integrate companies and properties that we acquire;

• our ability to execute our business strategies and other corporate actions, including restructuring our balance sheet and gathering and transportation contracts; and

• our ability to continue as a going concern.

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. We caution users of the financial statements not to place undue reliance on any forward-looking statements. When considering our forward-looking statements, keep in mind the cautionary statements in this Quarterly Report on Form 10-Q, and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2015, filed with the Securities and Exchange Commission ("SEC") on March 2, 2016 ("2015 Form 10-K").

Our revenues, operating results and financial condition depend substantially on prevailing prices for oil and natural gas and the availability of capital. Declines in oil or natural gas prices may have a material adverse effect on our financial condition, liquidity, results of operations, the amount of oil or natural gas that we can produce economically and the ability to fund our operations. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

Overview and history

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. Our primary strategy focuses on the exploitation and development of our shale resource plays and the pursuit of leasing and acquisition opportunities. We plan to carry out this strategy by executing on a strategic plan that incorporates the following three core objectives: (i) restructuring the balance sheet to enhance our capital structure and extend structural liquidity; (ii) transforming EXCO into the lowest cost producer; and (iii) optimizing and repositioning our portfolio. We believe this strategy will allow us to create long-term value for our shareholders.

Like all oil and natural gas exploration and production companies, we face the challenge of natural production declines. We attempt to offset the impact of this natural decline by implementing drilling and exploitation projects to identify and develop additional reserves and by adding reserves through leasing and undeveloped acreage acquisition opportunities. Our liquidity and ability to maintain compliance with debt covenants have been negatively impacted by the prolonged depressed oil and natural gas price environment, levels of indebtedness, and gathering, transportation and certain other commercial contracts. If we are not able to execute transactions to improve our financial condition, we do not believe we will be able to comply with all of the covenants under our credit agreement ("EXCO Resources Credit Agreement") or have sufficient liquidity to conduct our business operations based on existing conditions and estimates during the next twelve months. See "Note 1. Organization and basis of presentation" in the Notes to our Condensed Consolidated Financial Statements and "Our liquidity, capital resources and capital commitments" section for further discussion regarding factors that raise substantial doubt about our ability to continue as a going concern.

Recent developments

Natural gas sales and firm transportation contract litigation

During the third quarter of 2016, Raider Marketing, LP ("Raider"), a wholly owned subsidiary of EXCO, terminated its sales and transportation contracts with Enterprise Products Operating LLC (“Enterprise”) and Acadian Gas Pipeline System (“Acadian”), respectively. We transported natural gas produced from our operated wells in North Louisiana through Acadian, and Enterprise was a purchaser of certain volumes of our natural gas, until we terminated the contracts. The termination of these contracts is currently subject to litigation. See "Note 9. Commitments and contingencies" in the Notes to our Condensed Consolidated Financial Statements and "Item 1. Legal Proceedings" for additional information.

Tender Offer and note repurchases

On August 24, 2016, we completed a cash tender offer for our outstanding senior unsecured notes ("Tender Offer") which resulted in the repurchase of an aggregate of $101.3 million in principal amount of our 8.5% senior unsecured notes due April

33

15, 2022 ("2022 Notes") for an aggregate purchase price of $40.0 million. See "Note 8. Debt" in the Notes to our Condensed Consolidated Financial Statements for a more detailed discussion of the Tender Offer. During the nine months ended September 30, 2016, through the Tender Offer and a series of open market purchases, we repurchased an aggregate of $26.4 million and $152.7 million in principal amount of our 7.5% senior unsecured notes due September 15, 2018 ("2018 Notes") and 2022 Notes, respectively, with an aggregate of $53.3 million in cash. These repurchases resulted in net gains on extinguishment of debt of $57.4 million and $119.4 millionfor the three and nine months endedSeptember 30, 2016, respectively. In conjunction with the Tender Offer, we solicited consents from the holders of the 2022 Notes to amend certain terms of the indenture governing the 2022 Notes. Following the consummation of the consent solicitation, we entered into a supplemental indenture governing the 2022 Notes to amend the definition of "Credit Facilities" to include debt securities as a permitted form of additional secured indebtedness, in addition to the term loans and other credit facilities currently permitted. We paid $0.7 million to the holders of the 2022 Notes in connection with the consent solicitation.

Settlement of Participation Agreement litigation

In July 2013, we entered into a participation agreement with a joint venture partner for the development of certain assets in the Eagle Ford shale ("Participation Agreement"). As described in "Item 3. Legal Proceedings" in our 2015 Form 10-K, we were in a dispute subject to litigation over the offer and the acceptance process with our joint venture partner. On July 25, 2016, we settled the litigation with our joint venture partner, and the litigation was thereafter dismissed after a final judgment order was entered in response to the parties’ joint motion to dismiss the case with prejudice. Among other things, the settlement provided a full release for any claims, rights, demands, damages and causes of action that either party has asserted or could have asserted for any breach of the Participation Agreement. As part of the settlement, the parties amended and restated the Participation Agreement to (i) eliminate our requirement to offer to purchase our joint venture partner's interests in certain wells each quarter, (ii) eliminate our requirement to convey a portion of our working interest to our joint venture partner upon commencing development of future locations, (iii) terminate the area of mutual interest, which required either party acquiring an interest in non-producing acreage included in certain areas to provide notice of the acquisition to the non-acquiring party and allowed the non-acquiring party to acquire a proportionate share in such acquired interest, (iv) provide that EXCO transfer to its joint venture partner a portion of its interests in certain producing wells and certain undeveloped locations in South Texas, effective May 1, 2016 and (v) modify or eliminate certain other provisions. See "Note 9. Commitments and contingencies" in the Notes to our Condensed Consolidated Financial Statements for additional information.

Divestitures

We executed a series of non-core asset divestitures as part of our objective to optimize and reposition our portfolio. On October 3, 2016, we closed the sale of our interests in shallow conventional assets located in West Virginia for approximately $4.5 million, subject to customary post-closing purchase price adjustments. For the nine months ended September 30, 2016, the divested assets produced approximately 4 Mmcfe per day and the revenues less direct operating expenses, excluding general and administrative costs, generated net income of $0.7 million. The asset retirement obligations related to the divested wells were $9.7 million on September 30, 2016.

On July 1, 2016, we closed the sale of our interests in shallow conventional assets located in Pennsylvania and received an overriding royalty interest in each well and approximately $0.1 million, subject to customary post-closing purchase price adjustments. For the six months ended June 30, 2016, the divested assets produced approximately 6 Mmcfe per day and the revenues less direct operating expenses, excluding general and administrative costs, generated a net loss of less than $0.1 million. The asset retirement obligations related to the divested wells were $22.6 million on July 1, 2016.

On May 6, 2016, we closed a sale of certain non-core undeveloped acreage in South Texas and our interests in four producing wells for $11.5 million, subject to customary post-closing purchase price adjustments.

See "Note 3. Divestitures" in the Notes to our Condensed Consolidated Financial Statements for additional information.

EXCO Resources Credit Agreement

On March 29, 2016, the lenders under the EXCO Resources Credit Agreement completed their regular semi-annual borrowing base redetermination, which resulted in a reduction in our borrowing base from $375.0 million to $325.0 million, primarily due to depressed oil and natural gas prices. There were no other changes or amendments to the EXCO Resources Credit Agreement as a result of the redetermination. On September 1, 2016, the lenders under the EXCO Resources Credit Agreement postponed the scheduled redetermination of the borrowing base from September 1, 2016 to November 1, 2016 at our request. We are currently working with the lenders to amend the EXCO Resources Credit Agreement and the redetermination of the borrowing base is still in progress. There is no assurance that we will be able to amend the EXCO Resources Credit Agreement and our lenders have discretion in the timing and amount during the borrowing base

34

redetermination process. In connection with the postponed redetermination, we may not request borrowings from the lenders under the EXCO Resources Credit Agreement that would result in their aggregate exposure to exceed $300.0 million, including letters of credit, until the effective date of the postponed redetermination.

Critical accounting policies

We consider accounting policies related to our estimates of proved reserves, oil and natural gas properties, derivatives, business combinations, equity-based compensation, goodwill, revenue recognition, asset retirement obligations and income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates were made. However, these estimates could change materially if different information or assumptions were used. These policies and others are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in EXCO's 2015 Form 10-K.

Our results of operations

A summary of key financial data for the three and nine months endedSeptember 30, 2016 and 2015 related to our results of operations is presented below:

35

	Three Months Ended September 30,					Quarter to quarter change			Nine Months Ended September 30,						Period to period change
(dollars in thousands, except per unit prices)	2016		2015						2016			2015
Production:
Oil (Mbbls)	391		635			(244		)	1,388			1,733			(345		)
Natural gas (Mmcf)	24,107		27,493			(3,386		)	71,926			84,257			(12,331		)
Total production (Mmcfe) (1)	26,453		31,303			(4,850		)	80,254			94,655			(14,401		)
Average daily production (Mmcfe)	288		340			(52		)	293			347			(54		)
Revenues before derivative financial instrument activities:
Oil	$	16,215	$	27,444		$	(11,229	)	$	49,688		$	79,872		$	(30,184	)
Natural gas	54,647		56,300			(1,653		)	127,044			184,275			(57,231		)
Total oil and natural gas revenues	70,862		83,744			(12,882		)	176,732			264,147			(87,415		)
Purchased natural gas and marketing	6,324		6,773			(449		)	15,335			21,012			(5,677		)
Total revenues	$	77,186	$	90,517		$	(13,331	)	$	192,067		$	285,159		$	(93,092	)
Oil and natural gas derivative financial instruments:
Gain (loss) on derivative financial instruments	$	8,209	$	37,348		$	(29,139	)	$	(11,632	)	$	54,427		$	(66,059	)
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	41.47	$	43.22		$	(1.75	)	$	35.80		$	46.09		$	(10.29	)
Natural gas (per Mcf)	2.27		2.05			0.22			1.77			2.19			(0.42		)
Natural gas equivalent (per Mcfe)	2.68		2.68			—			2.20			2.79			(0.59		)
Costs and expenses:
Oil and natural gas operating costs	$	8,797	$	12,669		$	(3,872	)	$	25,835		$	41,745		$	(15,910	)
Production and ad valorem taxes	3,811		5,944			(2,133		)	13,308			16,408			(3,100		)
Gathering and transportation	27,979		23,743			4,236			79,828			74,243			5,585
Purchased natural gas	6,586		6,991			(405		)	17,273			21,571			(4,298		)
Depletion	15,528		51,494			(35,966		)	62,848			174,509			(111,661		)
Depreciation and amortization	382		519			(137		)	1,147			1,651			(504		)
General and administrative (2)	10,746		13,393			(2,647		)	38,626			41,227			(2,601		)
Interest expense, net	16,997		27,761			(10,764		)	54,186			80,822			(26,636		)
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.33	$	0.40		$	(0.07	)	$	0.32		$	0.44		$	(0.12	)
Production and ad valorem taxes	0.14		0.19			(0.05		)	0.17			0.17			—
Gathering and transportation	1.06		0.76			0.30			0.99			0.78			0.21
Depletion	0.59		1.65			(1.06		)	0.78			1.84			(1.06		)
Depreciation and amortization	0.01		0.02			(0.01		)	0.01			0.02			(0.01		)
Net income (loss) (3)	$	50,936	$	(354,519	)	$	405,455		$	(190,559	)	$	(1,126,786	)	$	936,227

(1) Mmcfe is calculated by converting one barrel of oil into six Mcf of natural gas.

(2) Equity-based compensation expense included in general and administrative expense was $1.4 million and $0.9 millionfor the three months endedSeptember 30, 2016 and 2015, respectively, and $14.6 million and $4.0 millionfor the nine months endedSeptember 30, 2016 and 2015, respectively.

(3) Net loss for the three months ended September 30, 2015 included $339.4 million of impairments of oil and natural gas properties. Net losses for the nine months endedSeptember 30, 2016 and 2015 included $160.8 million and $1.0 billion of impairments of oil and natural gas properties, respectively. See "Note 5. Oil and natural gas properties" in the Notes to our Condensed Consolidated Financial Statements for further discussion. Net income and net loss for the three and nine months ended September 30, 2016 included a net gain on extinguishment of debt of $57.4 million and $119.4 million, respectively.

The following is a discussion of our financial condition and results of operations for the three and nine months endedSeptember 30, 2016 and 2015. The comparability of our results of operations for the three and nine months endedSeptember 30, 2016 and 2015 was affected by:

36

• fluctuations in oil and natural gas prices, which impact our oil and natural gas reserves, revenues, cash flows and net income or loss;

• impairments of our oil and natural gas properties during 2016 and 2015;

• asset impairments and other non-recurring costs, including the settlement of the litigation with our Eagle Ford shale joint venture partner during 2016;

• mark-to-market gains and losses from our derivative financial instruments;

• changes in proved reserves and production volumes and their impact on depletion;

• the impact of declining natural gas production volumes from our reduced drilling activities;

• significant changes in our capital structure as a result of transactions in 2016 and 2015, including the issuance of the Second Lien Term Loans and repurchases and exchanges of our 2018 Notes and 2022 Notes;

• changes in general and administrative expenses as a result of the services and investment agreement with Energy Strategic Advisory Services LLC ("ESAS") and legal and advisory fees incurred in connection with the restructuring of our balance sheet and gathering and firm transportation contracts; and

• the reductions in our workforce that occurred during 2016 and 2015.

The availability of a ready market and the prices for oil and natural gas are dependent upon a number of factors that are beyond our control. These factors include, among other things:

• supply and demand for oil and natural gas and expectations regarding supply and demand;

• the level of domestic and international production;

• the availability of imported oil and natural gas;

• federal regulations applicable to the export of, and construction of export facilities for natural gas;

• political and economic conditions and events in foreign oil and natural gas producing nations, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;

• the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• the cost and availability of transportation and pipeline systems with adequate capacity;

• the cost and availability of other competitive fuels;

• fluctuating and seasonal demand for oil, natural gas and refined products;

• concerns about global warming or other conservation initiatives and the extent of governmental price controls and regulation of production;

• regional price differentials and quality differentials of oil and natural gas;

• the availability of refining capacity;

• technological advances affecting oil and natural gas production and consumption;

• weather conditions and natural disasters;

• foreign and domestic government relations; and

• overall domestic and global economic conditions.

Accordingly, in light of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we cannot accurately predict the prices or marketability of oil and natural gas from any producing well in which we have or may acquire an interest.

Oil and natural gas production, revenues and prices

The following table presents our production, revenue and average sales prices for the three and nine months endedSeptember 30, 2016 and 2015:

	Three Months Ended September 30,
	2016					2015					Quarter to quarter change
(dollars in thousands, except per unit rate)	Production (Mmcfe)	Revenue		$/Mcfe		Production (Mmcfe)	Revenue		$/Mcfe		Production (Mmcfe)		Revenue			$/Mcfe
Producing region:
North Louisiana	14,633	$	34,856	$	2.38	18,161	$	39,349	$	2.17	(3,528	)	$	(4,493	)	$	0.21
East Texas	6,312	16,424		2.60		4,763	12,516		2.63		1,549		3,908			(0.03		)
South Texas	2,517	14,953		5.94		4,064	25,450		6.26		(1,547	)	(10,497		)	(0.32		)
Appalachia and other	2,991	4,629		1.55		4,315	6,429		1.49		(1,324	)	(1,800		)	0.06
Total	26,453	$	70,862	$	2.68	31,303	$	83,744	$	2.68	(4,850	)	$	(12,882	)	$	—

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	Nine Months Ended September 30,
	2016					2015					Period to period change
(dollars in thousands, except per unit rate)	Production (Mmcfe)	Revenue		$/Mcfe		Production (Mmcfe)	Revenue		$/Mcfe		Production (Mmcfe)		Revenue			$/Mcfe
Producing region:
North Louisiana	41,639	$	76,044	$	1.83	57,851	$	133,751	$	2.31	(16,212	)	$	(57,707	)	$	(0.48	)
East Texas	18,933	39,607		2.09		12,465	33,603		2.70		6,468		6,004			(0.61		)
South Texas	9,003	45,542		5.06		11,183	75,082		6.71		(2,180	)	(29,540		)	(1.65		)
Appalachia and other	10,679	15,539		1.46		13,156	21,711		1.65		(2,477	)	(6,172		)	(0.19		)
Total	80,254	$	176,732	$	2.20	94,655	$	264,147	$	2.79	(14,401	)	$	(87,415	)	$	(0.59	)

Production for the three and nine months endedSeptember 30, 2016decreased by 4.9 Bcfe, or 15%, and 14.4 Bcfe, or 15%, respectively, as compared with the same periods in 2015. Significant components of the changes in production were a result of:

• decreased production of 3.5 Bcfe and 16.2 Bcfe for the three and nine months endedSeptember 30, 2016, respectively, in the North Louisiana region, primarily due to production declines partially offset by additional volumes from the wells turned-to-sales in the second and third quarters of 2016.

• increased production of 1.5 Bcfe and 6.5 Bcfe for the three and nine months endedSeptember 30, 2016, respectively, in the East Texas region, primarily due to additional volumes from wells turned-to-sales.

• decreased production in the South Texas region of 1.5 Bcfe and 2.2 Bcfe for the three and nine months endedSeptember 30, 2016, respectively, primarily due to production declines and the transfer of a portion of our interests in certain producing wells to a joint venture partner. The transfer of our interests was the result of the litigation settlement with a joint venture partner that is described in more detail in "Note 9. Commitments and contingencies" in the Notes to our Condensed Consolidated Financial Statements.

• decreased production of 1.3 Bcfe and 2.5 Bcfe for the three and nine months endedSeptember 30, 2016, respectively, in the Appalachia region primarily due to the sale of our interests in shallow conventional assets located in Pennsylvania in July 2016 and production declines. In addition, we shut-in approximately 0.8 Bcfe of production due to low regional natural gas prices during the nine months ended September 30, 2016. The regional natural gas price differential significantly widened late in the third quarter of 2016 and into the fourth quarter of 2016. As a result, we have shut-in production for certain Marcellus shale wells in the region until natural gas prices improve. As discussed in "Note 3. Divestitures" in the Notes to our Condensed Consolidated Financial Statements, on October 3, 2016, we closed a sale of our interests in shallow conventional assets located in West Virginia. As such, our production in the Appalachia region for the remainder of 2016 is expected to further decline.

Oil and natural gas revenues for the three months endedSeptember 30, 2016decreased by $12.9 million, or 15%, as compared with the same period in 2015. The decrease in revenues was primarily the result of a decrease oil and natural gas production partially offset by an increase in natural gas prices. The reduction in our development activities and suspension of drilling in certain regions will cause our production to continue to decline unless we increase our development program. Our average natural gas sales price increased11% to $2.27 per Mcf for the three months endedSeptember 30, 2016 from $2.05 per Mcf for the three months endedSeptember 30, 2015, primarily due to improved differentials from a renegotiated sales contract and taking our gas in-kind from certain third-party operated wells. Our average sales price of oil per Bbl decreased4% to $41.47 per Bbl for the three months endedSeptember 30, 2016 from $43.22 per Bbl for the three months endedSeptember 30, 2015, primarily due to lower market prices.

Oil and natural gas revenues for the nine months endedSeptember 30, 2016decreased by $87.4 million, or 33%, as compared with the same period in 2015. The decrease in revenues was primarily the result of a decrease in oil and natural gas prices as well as decreased oil and natural gas production. Our average natural gas sales price decreased19% to $1.77 per Mcf for the nine months endedSeptember 30, 2016 from $2.19 per Mcf for the nine months endedSeptember 30, 2015, primarily due to lower market prices. Our average sales price of oil per Bbl decreased22% to $35.80 per Bbl for the nine months endedSeptember 30, 2016 from $46.09 per Bbl for the nine months endedSeptember 30, 2015, primarily due to lower market prices.

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Purchased natural gas and marketing revenues

Purchased natural gas and marketing revenues include revenues we receive as a result of selling natural gas purchased from third parties and marketing fees we receive from third parties. Purchased natural gas and marketing revenues for the three months ended September 30, 2016 decreased by $0.4 million, or 7%, as compared with the same period in 2015. The decrease was primarily due to lower volumes sold partially offset by marketing fees charged to third parties beginning in September 2016. Purchased natural gas and marketing revenues for the nine months ended September 30, 2016 decreased by $5.7 million, or 27%, as compared with the same period in 2015, primarily due to lower volumes sold and lower sales prices.

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Oil and natural gas operating costs

The following tables present our operating costs for the three and nine months endedSeptember 30, 2016 and 2015:

	Three Months Ended September 30,
	2016						2015						Quarter to quarter change
(in thousands)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
North Louisiana	$	2,841	$	341	$	3,182	$	3,386	$	252	$	3,638	$	(545	)	$	89		$	(456	)
East Texas	1,482		23		1,505		967		238		1,205		515			(215		)	300
South Texas	2,937		—		2,937		3,814		944		4,758		(877		)	(944		)	(1,821		)
Appalachia and other	1,131		42		1,173		2,753		315		3,068		(1,622		)	(273		)	(1,895		)
Total	$	8,391	$	406	$	8,797	$	10,920	$	1,749	$	12,669	$	(2,529	)	$	(1,343	)	$	(3,872	)
	Three Months Ended September 30,
	2016						2015						Quarter to quarter change
(per Mcfe)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
North Louisiana	$	0.19	$	0.02	$	0.21	$	0.19	$	0.01	$	0.20	$	—		$	0.01		$	0.01
East Texas	0.23		—		0.23		0.20		0.05		0.25		0.03			(0.05		)	(0.02		)
South Texas	1.17		—		1.17		0.94		0.23		1.17		0.23			(0.23		)	—
Appalachia and other	0.38		0.01		0.39		0.64		0.07		0.71		(0.26		)	(0.06		)	(0.32		)
Total	$	0.32	$	0.01	$	0.33	$	0.35	$	0.05	$	0.40	$	(0.03	)	$	(0.04	)	$	(0.07	)

	Nine Months Ended September 30,
	2016						2015						Period to period change
(in thousands)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
North Louisiana	$	8,421	$	493	$	8,914	$	9,814	$	2,637	$	12,451	$	(1,393	)	$	(2,144	)	$	(3,537	)
East Texas	3,746		229		3,975		2,983		1,027		4,010		763			(798		)	(35		)
South Texas	8,506		246		8,752		14,647		1,756		16,403		(6,141		)	(1,510		)	(7,651		)
Appalachia and other	4,152		42		4,194		8,441		440		8,881		(4,289		)	(398		)	(4,687		)
Total	$	24,825	$	1,010	$	25,835	$	35,885	$	5,860	$	41,745	$	(11,060	)	$	(4,850	)	$	(15,910	)
	Nine Months Ended September 30,
	2016						2015						Period to period change
(per Mcfe)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
North Louisiana	$	0.20	$	0.01	$	0.21	$	0.17	$	0.05	$	0.22	$	0.03		$	(0.04	)	$	(0.01	)
East Texas	0.20		0.01		0.21		0.24		0.08		0.32		(0.04		)	(0.07		)	(0.11		)
South Texas	0.94		0.03		0.97		1.31		0.16		1.47		(0.37		)	(0.13		)	(0.50		)
Appalachia and other	0.39		—		0.39		0.64		0.03		0.67		(0.25		)	(0.03		)	(0.28		)
Total	$	0.31	$	0.01	$	0.32	$	0.38	$	0.06	$	0.44	$	(0.07	)	$	(0.05	)	$	(0.12	)

Oil and natural gas operating costs for the three and nine months endedSeptember 30, 2016decreased by $3.9 million, or 31%, and $15.9 million, or 38%, respectively, as compared with the same periods in 2015. The decreases were primarily due to cost reduction efforts, including significant reductions in labor costs, repair and maintenance costs, chemical treatment costs, workover activity and saltwater disposal costs. Reduced labor costs were primarily due to significant reductions in our

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workforce in 2015 and 2016. We sold our conventional assets in Pennsylvania and West Virginia in July 2016 and October 2016, respectively, and further reduced our workforce in the region. As such, our labor costs decreased in the Appalachia region for the three months ended September 30, 2016 and are expected to continue to decrease during the remainder of 2016. The reduction in saltwater disposal costs is primarily due to the renegotiation of contracts and more cost-efficient disposal methods.

Gathering and transportation

Gathering and transportation expenses for the three months ended September 30, 2016increased by $4.2 million, or 18%, as compared with the same period in 2015. Gathering and transportation expenses for the nine months endedSeptember 30, 2016 increased by $5.6 million, or 8%, as compared with the same period in 2015. The increases were primarily due to gathering expenses in connection with taking our gas in-kind from certain third-party operated wells in the North Louisiana region, and higher gathering costs on volumes from wells recently turned-to-sales in North Louisiana. Gathering and transportation expenses were $1.06 per Mcfe for the three months endedSeptember 30, 2016 as compared to $0.76 per Mcfe for the same period in 2015. Gathering and transportation expenses for the nine months endedSeptember 30, 2016 were $0.99 per Mcfe as compared to $0.78 per Mcfe for the same period 2015. The increases were primarily due to lower volumes in relation to fixed costs under gathering and firm transportation contracts in the East Texas and North Louisiana regions.

As a result of our planned reduction in development and related lower production volumes for 2016, our gathering and transportation cost per Mcfe is expected to increase due to the nature of the fixed costs associated with our gathering and firm transportation contracts. We continue to evaluate plans to restructure our gathering and transportation contracts; however, no assurance can be given as to outcome or timing of this process. In addition, as discussed in "Note 9. Commitments and Contingencies", we terminated certain sales and firm transportation agreements during the third quarter of 2016 that are currently subject to litigation. The termination of these contracts will not be reflected in our financial results until the litigation is resolved and it is deemed to be realized in accordance with generally accepted accounting principles in the United States ("GAAP").

Purchased natural gas expenses

Purchased natural gas expenses are purchases of natural gas from third parties plus the related costs of transportation. Purchased natural gas expenses for the three months ended September 30, 2016 decreased by $0.4 million, or 6%, as compared with the same period in 2015. The decrease was primarily due to lower volumes purchased partially offset by higher purchase prices. Purchased natural gas expenses for the nine months ended September 30, 2016 decreased by $4.3 million, or 20%, as compared with the same period in 2015, primarily due to lower volumes purchased.

Production and ad valorem taxes

The following table presents our production and ad valorem taxes on a percentage of revenue basis and per Mcfe basis for the three and nine months endedSeptember 30, 2016 and 2015:

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	Three Months Ended September 30,
	2016						2015
(in thousands, except per unit rate)	Production and ad valorem taxes		% of revenue		Taxes $/Mcfe		Production and ad valorem taxes		% of revenue		Taxes $/Mcfe
Producing region:
North Louisiana	$	1,627	4.7	%	$	0.11	$	2,431	6.2	%	$	0.13
East Texas	277		1.7	%	0.04		522		4.2	%	0.11
South Texas	1,626		10.9	%	0.65		2,592		10.2	%	0.64
Appalachia and other	281		6.1	%	0.09		399		6.2	%	0.09
Total	$	3,811	5.4	%	$	0.14	$	5,944	7.1	%	$	0.19
	Nine Months Ended September 30,
	2016						2015
(in thousands, except per unit rate)	Production and ad valorem taxes		% of revenue		Taxes $/Mcfe		Production and ad valorem taxes		% of revenue		Taxes $/Mcfe
Producing region:
North Louisiana	$	5,909	7.8	%	$	0.14	$	7,393	5.5	%	$	0.13
East Texas	864		2.2	%	0.05		822		2.4	%	0.07
South Texas	5,903		13.0	%	0.66		7,299		9.7	%	0.65
Appalachia and other	632		4.1	%	0.06		894		4.1	%	0.07
Total	$	13,308	7.5	%	$	0.17	$	16,408	6.2	%	$	0.17

Production and ad valorem taxes for the three months endedSeptember 30, 2016decreased by $2.1 million, or 36%, as compared with the same period in 2015, primarily due to lower production volumes in South Texas and North Louisiana and lower severance tax rates in North Louisiana. Production and ad valorem taxes for the nine months endedSeptember 30, 2016decreased by $3.1 million, or 19%, as compared to the same period in 2015. The decreases were primarily due to lower production volumes and lower commodity prices. The lower commodity prices primarily impacted properties located in Texas because production taxes are based on a fixed percentage of gross value of production sold.

In our North Louisiana region, we currently receive severance tax holidays that reduce the effective rate on certain horizontal wells. Our horizontal wells in the state of Louisiana are eligible for an exemption from severance taxes for the earlier of two years from the date of first production or until payout of qualified costs. In July 2015, the state of Louisiana decreased its severance tax rate for wells that do not receive exemptions from $0.163 to $0.158 per Mcf. In July 2016, the effective severance tax rate decreased to $0.098 per Mcf.

Depletion, depreciation and amortization

Depletion, depreciation and amortization for the three months endedSeptember 30, 2016 decreased from the same period in 2015 primarily due to a decrease in depletion expense of $36.0 million, or 70%. On a per Mcfe basis, the depletion rate for the three months endedSeptember 30, 2016 was $0.59 per Mcfe, compared with $1.65 per Mcfe in the same period in 2015. Depletion, depreciation and amortization for the nine months endedSeptember 30, 2016 decreased from the same period in 2015 primarily due to a decrease in depletion expense of $111.7 million, or 64%. On a per Mcfe basis, the depletion rate for the nine months endedSeptember 30, 2016 was $0.78 per Mcfe, compared with $1.84 per Mcfe in the same period in 2015. The decrease in depletion expense was primarily due to a decrease in production and the depletion rate. The decrease in the depletion rate was primarily due to the impairments of our oil and natural gas properties during 2015 and 2016, which lowered our depletable base.

Impairment of oil and natural gas properties

We did not record an impairment to our oil and natural gas properties for the three months ended September 30, 2016 and we recorded impairments of $160.8 million to our oil and natural gas properties for the nine months ended September 30, 2016. We recorded impairments to our proved oil and natural gas properties of $339.4 million and $1.0 billionfor the three and nine months endedSeptember 30, 2015, respectively. The impairments were primarily due to the significant decline in oil and natural gas prices. Oil and natural gas prices are volatile and we may incur additional impairments during 2016 if future oil and natural gas prices result in a decrease in the trailing twelve-month reference prices compared to September 30, 2016. The possibility and amount of any future impairment is difficult to predict, and will depend, in part, upon future oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs.

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General and administrative

The following table presents our general and administrative expenses for the three and nine months endedSeptember 30, 2016 and 2015:

	Three Months Ended September 30,									Nine Months Ended September 30,
(in thousands)	2016			2015			Quarter to quarter change			2016			2015			Period to period change
General and administrative expenses:
Gross general and administrative expenses	$	14,863		$	21,083		$	(6,220	)	$	42,635		$	65,014		$	(22,379	)
Technical services and service agreement charges	(1,312		)	(3,541		)	2,229			(5,705		)	(12,314		)	6,609
Operator overhead reimbursements	(3,463		)	(3,328		)	(135		)	(10,339		)	(9,872		)	(467		)
Capitalized salaries	(759		)	(1,748		)	989			(2,523		)	(5,646		)	3,123
General and administrative expenses, excluding equity-based compensation	9,329			12,466			(3,137		)	24,068			37,182			(13,114		)
Gross equity-based compensation	1,642			1,852			(210		)	14,990			6,906			8,084
Capitalized equity-based compensation	(225		)	(925		)	700			(432		)	(2,861		)	2,429
General and administrative expenses	$	10,746		$	13,393		$	(2,647	)	$	38,626		$	41,227		$	(2,601	)

General and administrative expenses for the three months ended September 30, 2016decreased by $2.6 million, or 20%, compared with the same period in 2015. General and administrative expenses for the nine months endedSeptember 30, 2016decreased by $2.6 million, or 6%, compared with the same period in 2015. Significant components of the changes in general and administrative expenses were a result of:

• decreased personnel costs of $7.0 million and $22.3 millionfor the three and nine months endedSeptember 30, 2016, respectively, primarily due to reductions in our workforce and employee benefits.

• increased consulting and contract labor costs of $0.5 million and $1.8 millionfor the three and nine months endedSeptember 30, 2016, respectively, primarily related to the service fees and annual incentive payment with ESAS that began on March 31, 2015.

• increased professional and legal fees of $2.6 million and $3.0 million for the three and nine months ended September 30, 2016, respectively, primarily related to the legal and advisory fees incurred in connection with the strategic initiatives focused on restructuring our balance sheet and gathering and transportation contracts. These fees totaled $2.6 million for the three and nine months ended September 30, 2016 and we expect to continue to incur these costs until the completion of these initiatives.

• decreased various other gross general and administrative expenses of $2.3 million and $4.9 millionfor the three and nine months endedSeptember 30, 2016, respectively. These decreases reflect our efforts to reduce our general and administrative costs throughout the organization.

• decreased technical services and service agreement recoveries of $2.2 million and $6.6 millionfor the three and nine months endedSeptember 30, 2016, respectively. These decreases were primarily a result of reduced headcount and lower recoveries in connection with the transition service agreement with Compass Productions Partners, LP ("Compass") that terminated in April 2015.

• decreased capitalized salaries of $1.0 million and $3.1 millionfor the three and nine months endedSeptember 30, 2016, respectively, primarily as a result of reduced employee headcount.

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• increased equity-based compensation of $0.5 million and $10.5 millionfor the three and nine months endedSeptember 30, 2016, respectively. These increases were primarily due to $0.7 million and $11.6 million of additional compensation expense related to the warrants issued to ESAS in 2015 for the three and nine months endedSeptember 30, 2016, respectively, compared to the same periods in the prior year. The fair value of the warrants is dependent on factors such as our share price, historical volatility, risk-free rate and performance relative to our peer group. These factors, in aggregate, contributed to a significant increase in the fair value of the warrants and the related equity-based compensation expense at September 30, 2016. The expense related to warrants is re-measured and adjusted each interim reporting period; therefore, our general and administrative expenses in future periods could be volatile based on the aforementioned factors. The increase in our equity-based compensation expense was partially offset by lower equity-based compensation to employees as a result of reductions in our workforce.

Other operating items

Other operating items were a net gain of $1.1 million and a net loss of $23.9 millionfor the three and nine months endedSeptember 30, 2016 primarily due to the settlement of the litigation with our joint venture partner. See "Note 9. Commitments and Contingencies" in the Notes to our Condensed Consolidated Financial Statements for additional information.

Interest expense, net

The following table presents our interest expense, net for the three and nine months endedSeptember 30, 2016 and 2015:

	Three Months Ended September 30,									Nine Months Ended September 30,
(in thousands)	2016			2015			Quarter to quarter change			2016			2015			Period to period change
Interest expense, net:
EXCO Resources Credit Agreement	$	1,585		$	2,024		$	(439	)	$	3,890		$	5,672		$	(1,782	)
Fairfax Term Loan	9,375			—			9,375			28,125			—			28,125
2018 Notes	2,571			14,426			(11,855		)	8,076			43,259			(35,183		)
2022 Notes	2,512			10,625			(8,113		)	10,819			31,875			(21,056		)
Amortization of deferred financing costs	2,184			3,745			(1,561		)	7,052			10,012			(2,960		)
Capitalized interest	(1,297		)	(3,094		)	1,797			(3,939		)	(10,121		)	6,182
Other	67			35			32			163			125			38
Total interest expense, net	$	16,997		$	27,761		$	(10,764	)	$	54,186		$	80,822		$	(26,636	)

Interest expense, net for the three and nine months endedSeptember 30, 2016decreased $10.8 million and $26.6 million, respectively, from the same periods in 2015. These decreases were primarily due to lower outstanding balances on the 2018 Notes and 2022 Notes from debt restructuring activities and note repurchases in 2015 and 2016. This was partially offset by additional interest from the 12.5% senior secured second lien term loan with certain affiliates of Fairfax Financial Holdings Limited in the aggregate principal amount of $300.0 million ("Fairfax Term Loan"), which closed in the fourth quarter of 2015. The decreases were also partially offset by lower capitalized interest primarily related to lower balances of unproved oil and natural gas properties and suspension of our drilling and development program in certain areas.

In the fourth quarter of 2015, we closed a 12.5% senior secured second lien term loan with certain unsecured noteholders in the aggregate principal amount of $400.0 million (“Exchange Term Loan," and together with the Fairfax Term Loan, the "Second Lien Term Loans") and used the proceeds to repurchase a portion of the outstanding 2018 Notes and 2022 Notes in exchange for the holders of such notes agreeing to act as lenders in connection with the Exchange Term Loan. The exchange was accounted for as a troubled debt restructuring pursuant to FASB ASC 470-60, Troubled Debt Restructuring by Debtors. As such, all cash payments under the terms of the Exchange Term Loan, whether designated as interest or as principal amount, reduce the carrying amount and no interest expense, in accordance with GAAP, is recognized. This will result in a significantly lower interest expense than the contractual interest payments throughout the term of the Exchange Term Loan. 

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Derivative financial instruments

Our oil and natural gas derivative financial instruments resulted in net gains of $8.2 million and $37.3 millionfor the three months endedSeptember 30, 2016 and 2015, respectively. Our oil and natural gas derivative financial instruments resulted in a net loss of $11.6 millionfor the nine months endedSeptember 30, 2016 and a net gain of $54.4 millionfor the nine months endedSeptember 30, 2015, respectively. Based on the nature of our derivative contracts, increases in the related commodity price typically result in a decrease to the value of our derivatives contracts. The significant fluctuations demonstrate the high volatility in oil and natural gas prices between each of the periods. The ultimate settlement amount of the unrealized portion of the derivative financial instruments is dependent on future commodity prices.

The following table presents our oil and natural gas prices, before and after the impact of the cash settlement of our derivative financial instruments:

	Three Months Ended September 30,							Nine Months Ended September 30,
Average realized pricing:	2016		2015		Quarter to quarter change			2016		2015		Period to period change
Natural gas (per Mcf):
Net price, excluding derivatives	$	2.27	$	2.05	$	0.22		$	1.77	$	2.19	$	(0.42	)
Cash receipts on derivatives	0.04		0.70		(0.66		)	0.34		0.67		(0.33		)
Net price, including derivatives	$	2.31	$	2.75	$	(0.44	)	$	2.11	$	2.86	$	(0.75	)
Oil (per Bbl):
Net price, excluding derivatives	$	41.47	$	43.22	$	(1.75	)	$	35.80	$	46.09	$	(10.29	)
Cash receipts on derivatives	9.65		19.97		(10.32		)	9.93		18.95		(9.02		)
Net price, including derivatives	$	51.12	$	63.19	$	(12.07	)	$	45.73	$	65.04	$	(19.31	)
Natural gas equivalent (per Mcfe):
Net price, excluding derivatives	$	2.68	$	2.68	$	—		$	2.20	$	2.79	$	(0.59	)
Cash receipts on derivatives	0.18		1.02		(0.84		)	0.47		0.94		(0.47		)
Net price, including derivatives	$	2.86	$	3.70	$	(0.84	)	$	2.67	$	3.73	$	(1.06	)

Our total cash receipts for the three months endedSeptember 30, 2016 were $4.7 million, or $0.18 per Mcfe, compared to cash receipts of $31.9 million, or $1.02 per Mcfe, for the three months endedSeptember 30, 2015. Our total cash receipts for the nine months endedSeptember 30, 2016 were $38.1 million, or $0.47 per Mcfe, compared to cash receipts of $89.0 million, or $0.94 per Mcfe, for the nine months endedSeptember 30, 2015. The differences between the cash receipts during 2016 and 2015 were primarily due to lower volumes hedged and lower strike prices in the current period.

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Gain on extinguishment of debt

For the three and nine months endedSeptember 30, 2016, we recorded net gains on extinguishment of debt of $57.4 million and $119.4 million, respectively. The net gain for the three months endedSeptember 30, 2016 was primarily the result of the Tender Offer in which we repurchased an aggregate of $101.3 million in principal amount of the 2022 Notes with an aggregate of $40.0 million in cash. The net gain for the nine months endedSeptember 30, 2016 was primarily due to the repurchases of an aggregate of $179.1 million in principal amount of the 2018 Notes and 2022 Notes with an aggregate of $53.3 million in cash through the Tender Offer and open market repurchases. The net gains included an acceleration of the related deferred financings costs and notes discount, as well as direct costs associated with the transactions.

Equity loss

Our equity loss was $0.8 million and $0.2 million for the three months ended September 30, 2016 and 2015, respectively. Our equity loss was $8.8 million and $1.5 millionfor the nine months endedSeptember 30, 2016 and 2015, respectively. The increase in our equity loss for the nine months endedSeptember 30, 2016 from the same period in 2015 was primarily due to a $4.9 million other than temporary impairment of our midstream investment in the East Texas and North Louisiana regions that we account for under the cost method of accounting. The impairment was primarily the result of reduced drilling activity in the region that is expected to reduce future cash flows of our investment. In addition, we recorded a net loss of $2.8 millionfor the nine months endedSeptember 30, 2016 from our equity method investment that owns and manages certain surface acreage in the North Louisiana region primarily due to its impairment of certain assets.

Income taxes

Our effective income tax rate for the three and nine months endedSeptember 30, 2016 and 2015 was zero, primarily due to prior losses arising from impairments of oil and natural gas properties that created deferred tax assets. These deferred tax assets have been fully reserved with valuation allowances. Our accumulated valuation allowance as of September 30, 2016 was approximately $1.4 billion and has fully offset our net deferred tax assets. We will continue to recognize deferred tax valuation allowances until the realization of deferred benefits becomes more likely than not. As a result of the repurchase of a portion of our senior unsecured notes during the nine months ended September 30, 2016, we had cancellation of debt income for tax purposes which reduced our net operating loss carryforwards ("NOLs") by $125.8 million.

The effective income tax rates, excluding the impact of the valuation allowances, would have been 38.3% and 38.1%for the three and nine months endedSeptember 30, 2016, respectively, and 38.5% and 38.7%for the three and nine months endedSeptember 30, 2015, respectively. The effective tax rates, excluding the impact of the valuation allowance, differ from the statutory tax rates primarily due to permanent differences between the amounts recorded for financial reporting purposes and the amounts used for income tax purposes. During the three and nine months ended September 30, 2016, we recognized deferred income tax expense of $1.0 million and $1.8 million, respectively, related to a deferred tax liability for tax deductible goodwill. During the nine months ended September 30, 2016, the book basis of goodwill exceeded the tax basis that caused the previous book and tax basis differences to change from a deferred tax asset to a deferred tax liability. The deferred tax liability related to goodwill is considered to have an indefinite life based on the nature of the underlying asset and cannot be offset under GAAP with a deferred tax asset with a definite life, such as NOLs. However, the deferred income tax expense is not expected to result in cash payments of income taxes in the foreseeable future.

Our liquidity, capital resources and capital commitments

Overview

Our primary sources of capital resources and liquidity have historically consisted of internally generated cash flows from operations, borrowing capacity under the EXCO Resources Credit Agreement, dispositions of non-strategic assets, joint ventures and capital markets when conditions are favorable. Factors that could impact our liquidity, capital resources and capital commitments include the following:

• the level of planned drilling activities;

• the results of our ongoing drilling programs;

• our ability to fund, finance or repay financing incurred in connection with acquisitions of oil and natural gas properties;

• the integration of acquisitions of oil and natural gas properties or other assets;

• our ability to effectively manage operating, general and administrative expenses and capital expenditure programs;

• reduced oil and natural gas revenues resulting from, among other things, depressed oil and natural gas prices and lower production from reductions to our drilling and development activities;

• our ability to mitigate commodity price volatility with derivative financial instruments;

• our ability to meet minimum volume commitments under firm transportation agreements and other fixed commitments, as well as our ability to restructure these contracts;

• potential acquisitions and/or dispositions of oil and natural gas properties or other assets;

• limitations on our ability to incur certain types of indebtedness in accordance with our debt agreements;

• our ability to pay interest on our outstanding indebtedness, including the quarterly payments related to the Second Lien Term Loans;

• reductions to our borrowing base;

• requirements to provide certain vendors and other parties with letters of credit as a result of our credit quality, which reduce the amount of available borrowings under the EXCO Resources Credit Agreement;

• additional debt restructuring activities including the repurchase of indebtedness, issuance of additional indebtedness or issuance of equity in exchange for indebtedness;

• our ability to maintain compliance with debt covenants; and

• the potential outcome of litigation related to certain natural gas sales and firm transportation contracts.

Recent events affecting liquidity

In response to the low commodity price environment, we have limited our development activities to preserve our capital resources and liquidity. The curtailment of the development of our properties will result in a decline in our production and reserves unless we increase our levels of development in the future. Our 2016 capital budget is expected to exceed our cash flows from operations and we expect that the deficit will be funded with borrowings under the EXCO Resources Credit Agreement.

We continue to evaluate and implement further cost reduction initiatives to mitigate the impact of low commodity prices on our cash flows and liquidity. Since December 31, 2015, we reduced the number of our general and administrative employees by approximately 26%, and reduced our field employees in the Appalachia region by 85% in conjunction with the sale of our conventional assets in Pennsylvania and West Virginia. We currently employ 191 persons as compared to 315 at December 31, 2015.

On March 29, 2016, the lenders under the EXCO Resources Credit Agreement completed their regular semi-annual borrowing base redetermination, which resulted in a reduction in our borrowing base from $375.0 million to $325.0 million primarily due to depressed oil and natural gas prices. There were no other changes or amendments to the EXCO Resources Credit Agreement as a result of the redetermination.

On August 24, 2016, we completed the Tender Offer that resulted in the repurchase of an aggregate of $101.3 million of the 2022 Notes for an aggregate purchase price paid of $40.0 million. Our decision to commence the Tender Offer process was part of EXCO’s comprehensive restructuring process focused on reducing indebtedness; however, it detrimentally impacted our near-term liquidity because the purchases were funded with borrowings under the EXCO Resources Credit Agreement. During the nine months ended September 30, 2016, through the Tender Offer and a series of open market repurchases, we repurchased an aggregate of $26.4 million and $152.7 million in principal amount of the 2018 Notes and 2022 Notes, respectively, with an aggregate of $53.3 million in cash. As a result, we reduced the principal amounts outstanding under our 2018 Notes and 2022 Notes to $131.6 million and $70.2 million, respectively.

On September 1, 2016, the lenders under the EXCO Resources Credit Agreement postponed the scheduled redetermination of the borrowing base from September 1, 2016 to November 1, 2016 at our request. We are currently working with the lenders to amend the EXCO Resources Credit Agreement and the redetermination of the borrowing base is still in progress. There is no assurance that we will be able to amend the EXCO Resources Credit Agreement and our lenders have discretion in the timing and amount during the borrowing base redetermination process. In connection with the postponed redetermination, we may not request borrowings from the lenders under the EXCO Resources Credit Agreement that would result in their aggregate exposure to exceed $300.0 million, including letters of credit, until the effective date of the postponed redetermination.

During the three months ended September 30, 2016, we borrowed an additional $93.0 million under the EXCO Resources Credit Agreement primarily to fund the Tender Offer repurchases, interest payments and working capital. Our working capital requirements during the three months ended September 30, 2016 were negatively impacted by a significant customer modifying their method of credit assurance from a prepayment to a letter of credit. Furthermore, the limitation on the aggregate exposure within the EXCO Resources Credit Agreement in connection with the postponement of the redetermination process further constrained our liquidity. As a result, the Company had $3.5 million in cash and cash equivalents and $75.4 million of availability under the EXCO Resources Credit Agreement at September 30, 2016.

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Our plans to improve near-term liquidity primarily include the issuance of additional indebtedness and we are engaged in discussions with potential lenders. The availability and terms of this financing may be dependent upon our ability to reduce fixed commitments including gathering and transportation contracts. We continue to negotiate a consensual restructuring of gathering and transportation contracts with our counterparties. Our ability to execute these plans is conditioned upon factors including the availability of capital markets, market conditions, and the actions of counterparties. There is no assurance any such transactions will occur.  

The following table presents our liquidity and outstanding principal balance of debt as of September 30, 2016:

(in thousands)	September 30, 2016
EXCO Resources Credit Agreement	$	214,592
Exchange Term Loan (1)	400,000
Fairfax Term Loan	300,000
2018 Notes (2)	131,576
2022 Notes	70,169
Total debt (3)	$	1,116,337
Net debt	$	1,094,369
Borrowing base (4)	$	300,000
Unused borrowing base (5)	$	75,372
Cash (6)	$	21,968
Unused borrowing base plus cash	$	97,340

(1) Amount presented is the outstanding principal balance and excludes $203.1 million of deferred reductions to carrying value. See "Note 8. Debt" in the Notes to our Condensed Consolidated Financial Statements for additional information.

(2) Excludes unamortized discount of $0.6 million at September 30, 2016.

(3) Excludes unamortized deferred financing costs of $12.8 million at September 30, 2016. Since September 30, 2016, we borrowed an additional $14.0 million under the EXCO Resources Credit Agreement.

(4) The borrowing base under the EXCO Resources Credit Agreement was $325.0 million as of September 30, 2016. In connection with the postponed redetermination, we may not request borrowings from the lenders under the EXCO Resources Credit Agreement that would result in their aggregate exposure to exceed $300.0 million, including letters of credit, until the effective date of the postponed redetermination. Therefore, we have incorporated the limitation on the aggregate exposure of the lenders to the borrowing base in the table above as it is more representative of our available borrowing capacity under the EXCO Resources Credit Agreement.

(5) Net of $10.0 million in letters of credit at September 30, 2016.

(6) Includes restricted cash of $18.4 million at September 30, 2016.

Credit agreements and long-term debt

As of September 30, 2016, our consolidated debt consisted of the EXCO Resources Credit Agreement, 2018 Notes, 2022 Notes and the Second Lien Term Loans. See "Note 8. Debt" in the Notes to our Condensed Consolidated Financial Statements for a more detailed description of each agreement.

As of September 30, 2016, we were in compliance with the following financial covenants (each as defined in the EXCO Resources Credit Agreement):

• our Consolidated Current Ratio of 1.1 to 1.0 exceeded the minimum of at least 1.0 to 1.0 as of the end of any fiscal quarter. The consolidated current assets utilized in this ratio include unused commitments under the EXCO Resources Credit Agreement. As of September 30, 2016, the unused commitments were based on the Company's borrowing base of $325.0 million;

• our ratio of consolidated EBITDAX to consolidated interest expense ("Interest Coverage Ratio"), of 1.6 to 1.0 exceeded the minimum of at least 1.25 to 1.0 as of the end of any fiscal quarter. The consolidated interest expense utilized in the Interest Coverage Ratio is calculated in accordance with GAAP; therefore, this excludes cash payments under the terms of the Exchange Term Loan, whether designated as interest or as principal amount, that reduce the carrying amount and are not recognized as interest expense. See further details on the accounting for the Exchange Term Loan in "Note 8. Debt" in the Notes to our Condensed Consolidated Financial Statements; and

• our ratio of senior secured indebtedness to consolidated EBITDAX ("Senior Secured Indebtedness Ratio") of 1.9 to 1.0 did not exceed the maximum of 2.5 to 1.0 as of the end of any fiscal quarter. Senior secured indebtedness

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utilized in the Senior Secured Indebtedness Ratio excludes the Second Lien Term Loans and any other indebtedness subordinated to the EXCO Resources Credit Agreement.

Our liquidity and ability to maintain compliance with debt covenants have been negatively impacted by the prolonged depressed oil and natural gas price environment, levels of indebtedness, and gathering, transportation and certain other commercial contracts. Based on our current estimates and expectations, we do not believe we will be able to comply with all of the covenants under the EXCO Resources Credit Agreement or have sufficient liquidity to conduct our business operations during the next twelve-month period following the date of these Condensed Consolidated Financial Statements. The next borrowing base redetermination under the EXCO Resources Credit Agreement is expected to occur in November 2016. The lenders party to the EXCO Resources Credit Agreement have considerable discretion in setting our borrowing base, and we are unable to predict the outcome of any future redeterminations.

As a result of the impact of the aforementioned factors on our financial results and condition, we anticipate that we will not meet the minimum requirement under the Consolidated Current Ratio and the Senior Secured Indebtedness Ratio for the twelve-month period following the date of these Condensed Consolidated Financial Statements. We may not be in compliance with these covenants as early as the fiscal quarter ending December 31, 2016 depending on our future financial and operating results and the outcome of the borrowing base redetermination process. The inclusion of the unused commitments under the EXCO Resources Credit Agreement has historically allowed us to maintain compliance with the Consolidated Current Ratio covenant. Therefore, the reduction in unused commitments as a result of borrowings under the EXCO Resources Credit Agreement or further reductions to our borrowing base as part of the redetermination process will negatively impact our Consolidated Current Ratio and liquidity. On a pro forma basis, we would not have been in compliance with the current ratio covenant if our borrowing base had been reduced by $20.0 million as of September 30, 2016. The Company's compliance with the Senior Secured Indebtedness ratio covenant will be negatively impacted unless we are able to increase our EBITDAX, generate positive free cash flows and/or find other sources of capital to reduce indebtedness under the EXCO Resources Credit Agreement.

Furthermore, our liquidity is not expected to be sufficient to conduct our business operations for the twelve-month period following the date of the Condensed Consolidated Financial Statements included herein. If we are not able to meet our debt covenants or do not have sufficient liquidity to conduct our business operations in future periods, we may be required, but unable, to refinance all or part of our existing debt, seek covenant relief from our lenders, sell assets, incur additional indebtedness, or issue 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. Therefore, our ability to continue our planned principal business operations would be dependent on the actions of our lenders or obtaining additional debt and/or equity financing to repay outstanding indebtedness under the EXCO Resources Credit Agreement. These factors raise substantial doubt about our ability to continue as a going concern.

The EXCO Resources Credit Agreement and Second Lien Term Loans require our annual financial statements to include a report from our independent registered public accounting firm without an explanatory paragraph related to our ability to continue as a going concern. If the substantial doubt about our ability to continue as a going concern still exists at December 31, 2016 or if we fail to comply with the financial and other covenants in the EXCO Resources Credit Agreement or the Second Lien Term Loans, we would be in default under such agreement. Any event of default may cause a default or accelerate our obligations with respect to our other outstanding indebtedness, including the 2018 Notes and 2022 Notes, which could adversely affect our business, financial condition and results of operations.

The Second Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes contain incurrence covenants that restrict our ability to incur additional indebtedness, incur liens to secure any such additional indebtedness or pledge assets. These incurrence covenants include limitations on our indebtedness that are based, in part, on the greater of a monetary threshold or the value of our assets. Our ability to incur additional indebtedness could be limited to the extent that low oil and natural gas prices negatively impact the value of our assets. See further details on the limitations on our ability to incur additional indebtedness as described in "Note 8. Debt" in the Notes to our Condensed Consolidated Financial Statements.

Capital expenditures

Our 2016 capital budget of $85.0 million is focused on development activities in the Haynesville and Bossier shales in North Louisiana and East Texas. The development activities included drilling 6 gross (5.2 net) wells and completing 14 gross (8.8 net) wells. We have flexibility in the timing of development because our acreage is predominantly held-by-production.

For the nine months endedSeptember 30, 2016, our capital expenditures totaled $69.7 million, of which $60.3 million was related to drilling and development activities. Our development program during the nine months endedSeptember 30, 2016 included an average of one operated drilling rig focused on the Haynesville shale in North Louisiana. We concluded our

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2016 drilling program in North Louisiana and turned-to-sales three additional wells in this region in the third quarter of 2016. Our two drilling rig contracts expire in 2017 and are currently being sub-leased to another operator. Our development activities in East Texas included completion activities in the Haynesville and Bossier shales.

The following table presents our capital expenditures for the nine months endedSeptember 30, 2016 and our forecasted capital expenditures for the remainder of 2016.

	Nine Months Ended		October - December Forecast		Full Year Forecast
(in thousands)	June 30, 2016		2016		2016
Capital expenditures:
Development capital expenditures	$	60,285	$	2,215	$	62,500
Other (1)	9,406		13,094		22,500
Total	$	69,691	$	15,309	$	85,000

(1) Other capital expenditures are comprised primarily of capitalized corporate costs, field operations and land costs.

Historical sources and uses of funds

Our primary sources of cash for the nine months endedSeptember 30, 2016 were cash flows from operations and borrowings under the EXCO Resources Credit Agreement.

Net increases (decreases) in cash are summarized as follows:

	Nine Months Ended September 30,
(in thousands)	2016			2015
Net cash provided by (used in) operating activities	$	(3,740	)	$	126,856
Net cash used in investing activities	(56,150		)	(255,854		)
Net cash provided by financing activities	51,177			103,204
Net decrease in cash	$	(8,713	)	$	(25,794	)

Operating activities

The primary factors impacting our cash flows from operating activities include: (i) levels of production from our oil and natural gas properties, (ii) prices we receive from sales of oil and natural gas production, including settlement proceeds or payments related to our oil and natural gas derivatives, (iii) operating costs of our oil and natural gas properties, (iv) costs of our general and administrative activities and (v) interest expense. Our cash flows from operating activities have historically been impacted by fluctuations in oil and natural gas prices and our production volumes.

For the nine months endedSeptember 30, 2016, our net cash used in operating activities was $3.7 million as compared to $126.9 million of net cash provided by operating activities for the nine months endedSeptember 30, 2015. The decrease was primarily attributable to lower revenues from lower production and decreased oil and natural gas prices. In addition, the decrease was due to lower cash receipts on derivative contracts of $38.1 millionfor the nine months endedSeptember 30, 2016 compared to $89.0 million for the same period in 2015.

The Company generated negative cash flow from operations for the nine months ended September 30, 2016 due to low oil and natural gas prices and declining production volumes. If we are not able to generate positive cash flow from operations in the future or obtain additional financing, we may not be able to continue our planned principal business operations, meet our working capital requirements, or repay indebtedness. See "Note 1. Organization and basis of presentation" in the Notes to our Condensed Consolidated Financial Statements for further discussion regarding factors that raise substantial doubt about our ability to continue as a going concern.

Investing activities

Our investing activities consist primarily of drilling and development expenditures, acquisitions and divestitures. Future acquisitions are dependent on oil and natural gas prices, availability of attractive acreage and other oil and natural gas properties, acceptable rates of return, availability of borrowing capacity under the EXCO Resources Credit Agreement and availability of other sources of capital.

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For the nine months endedSeptember 30, 2016, our net cash used in investing activities was $56.2 million that primarily consisted of $70.5 million of completion activities in the East Texas region and development activities in the North Louisiana region. This was partially offset by $11.2 million of proceeds received primarily from a sale of certain non-core undeveloped acreage in South Texas and our interests in four producing wells and other divestitures. For the nine months endedSeptember 30, 2015, our net cash used in investing activities was $255.9 million primarily due to drilling and completion activities in the East Texas, North Louisiana and South Texas regions. The cash used in investing activities for the nine months endedSeptember 30, 2015 included a significant amount of expenditures related to the wells drilled in 2014.

Financing activities

For the nine months endedSeptember 30, 2016, our net cash provided by financing activities was $51.2 million primarily due to $147.1 million in net borrowings under the EXCO Resources Credit Agreement partially offset by payments of $38.1 million on the Exchange Term Loan, which reduced its carrying value, and an aggregate of $53.3 million of cash payments used to repurchase a portion of our 2018 Notes and 2022 Notes. On March 29, 2016, we borrowed our remaining unused commitments of $232.4 million under the EXCO Resources Credit Agreement to secure our liquidity. Prior to the completion of the borrowing base redetermination process on March 29, 2016, we repaid the entire $232.4 million. The borrowing and subsequent repayment both occurred on the same day. For the nine months endedSeptember 30, 2015, our net cash provided by financing activities was $103.2 million primarily due to $97.5 million in borrowings under the EXCO Resources Credit Agreement and $9.8 million in net proceeds from the issuance of common shares to ESAS.

Derivative financial instruments

Our production is generally sold at prevailing market prices. However, we periodically enter into oil and natural gas derivative contracts for a portion of our production to mitigate the impact of commodity price fluctuations and achieve a more predictable cash flow associated with our operations. These transactions limit our exposure to declines in prices, but also limit the benefits we would realize if oil and natural gas prices increase.                     

Our derivative financial instruments are comprised of oil and natural gas swaps, collars and swaption contracts. As of September 30, 2016, we had derivative financial instruments in place for the volumes and prices shown below:

	NYMEX gas volume - Bbtu	Weighted average contract price per Mmbtu		NYMEX oil volume - Mbbl	Weighted average contract price per Bbl
Swaps:
Remainder of 2016	14,260	$	2.88	276	$	58.61
2017	23,700	2.99		183	50.00
2018	3,650	3.15		—	—
Swaptions:
2017	7,300	2.76		—	—
Collars:
2017	10,950			—
Sold call		3.28			—
Purchased put		2.87			—

We had derivative financial instruments that covered approximately 60% and 55% of production volumes during the three and nine months endedSeptember 30, 2016, respectively.

See further details on our derivative financial instruments in "Note 7. Derivative financial instruments" and "Note 10. Fair value measurements" in the Notes to our Condensed Consolidated Financial Statements.

Off-balance sheet arrangements

As of September 30, 2016, we had no arrangements or any guarantees of off-balance sheet debt to third parties.

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Contractual obligations and commercial commitments

On July 25, 2016, we amended and restated the Participation Agreement to eliminate our requirement to offer to purchase our joint venture partner's interests, eliminate our requirement to convey a portion of our working interest to our joint venture partner upon commencing development of future locations, terminate the area of mutual interest, provide that we transfer to our joint venture partner a portion of our interests in certain producing wells and modify or eliminate other provisions. See "Note 9. Commitments and Contingencies" in the Notes to our Condensed Consolidated Financial Statements for further discussion.

During the third quarter of 2016, we terminated our sales and transportation contracts with Enterprise and Acadian, respectively. We transported natural gas produced from our operated wells in North Louisiana through Acadian, and Enterprise was a purchaser of certain volumes of our natural gas, until we terminated the contracts. The agreement with Acadian provided for the firm transportation of 150,000 Mmbtu/day and 175,000 Mmbtu/day of natural gas at reservation fees of $0.25 and $0.20, respectively. In addition, the sales contract with Enterprise contemplated that we could, subject to certain limitations and exclusions, sell 75,000 Mmbtu/day of natural gas at a $0.25 reduction from market index prices. The primary term for these contracts had been through October 31, 2025. See "Note 9. Commitments and Contingencies" in the Notes to our Condensed Consolidated Financial Statements for further discussion.

There have been no other material changes outside the ordinary course of business to our contractual obligations and commercial commitments since December 31, 2015.

Item 3.     Quantitative and Qualitative Disclosures About Market Risk

Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices, interest rates charged on borrowings and earned on cash equivalent investments, and adverse changes in the market value of marketable securities. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for hedging and investment purposes, not for trading purposes.

Commodity price risk

Our 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 in connection with our financing activities and borrowings related to these activities. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if oil and natural gas 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 instrument contracts. 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. Our credit rating and financial condition may restrict our ability to enter into certain types of derivative financial instruments and limit the maturity of the contracts with counterparties.

Our most significant market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices for natural gas as well as local and regional differentials. Pricing for oil and natural gas production is volatile.

Our use of derivative financial instruments could have the effect of reducing our revenues and the value of our securities. For the nine months endedSeptember 30, 2016, a $1.00 increase in the average commodity price per Mcfe would have resulted in an increase in cash settlement payments (or a decrease in settlements received) of approximately $44.1 million for our oil and natural gas swap contracts. The ultimate settlement amount of our outstanding derivative financial instrument contracts is dependent on future commodity prices. We may incur significant unrealized losses in the future from our use of derivative financial instruments to the extent market prices increase and our derivatives contracts remain in place.

Interest rate risk

At September 30, 2016, our exposure to interest rate changes related primarily to borrowings under the EXCO Resources Credit Agreement. The interest rates per annum on the 2018 Notes, 2022 Notes and Second Lien Term Loans are fixed at 7.5%, 8.5% and 12.5%, respectively. Interest is payable on borrowings under the EXCO Resources Credit Agreement based on a floating rate as more fully described in "Note 8. Debt" in the Notes to our Condensed Consolidated Financial

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Statements. At September 30, 2016, we had approximately $214.6 million in outstanding borrowings under the EXCO Resources Credit Agreement. A 1% increase in interest rates (100 bps) based on the variable borrowings as of September 30, 2016 would result in an increase in our interest expense of approximately $2.1 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

Item 4.     Controls and Procedures

Disclosure controls and procedures. Pursuant to Rule 13a-15(b) under the Exchange Act, EXCO's management has evaluated, under the supervision and with the participation of our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and principal financial officer have concluded that EXCO's disclosure controls and procedures were effective as of September 30, 2016 to ensure that information that is required to be disclosed by EXCO in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms and (ii) accumulated and communicated to EXCO's management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There were no changes in EXCO's internal control over financial reporting that occurred during the quarter ended September 30, 2016 that have materially affected, or are reasonably likely to materially affect, EXCO's internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

During the third quarter of 2016, we terminated our sales and transportation contracts with Enterprise and Acadian, respectively. Under the parties’ sales and transportation agreements, Enterprise owed us for July 2016 natural gas sales, and we owed Acadian for July 2016 transportation fees. The amount owed to us by Enterprise exceeded the amount owed by us to Acadian. We notified Enterprise in writing of its failure to pay and gave Enterprise opportunity to cure. When Enterprise failed to cure, we gave written notice to Enterprise and Acadian that we were terminating the sales and transportation agreements. Enterprise subsequently filed an amended petition at Enterprise Products Operating LLC and Acadian Gas Pipeline System v. EXCO Operating Company, LP, EXCO Partners OLP GP, LLC, Raider Marketing, LP, and Raider Marketing GP, LLC No. 2016-60848 157th Judicial District, Harris County, Texas. The amended petition alleges that we could not terminate the parties’ agreements despite Enterprise's uncured payment default under the gas sales agreement, and further alleged that we were in breach of the firm transportation agreements. On October 17, 2016, we filed a counterclaim asserting that Enterprise was the breaching party because it improperly withheld payment for natural gas we delivered to it and the amounts owed by Enterprise exceeded the amounts owed by us to Acadian. We are also seeking a declaration that we properly terminated the contracts with Enterprise and Acadian, as well as payment of the amounts owed to us under the agreements.

Item 1A. Risk Factors

During the third quarter of 2016, there were no material changes to the Risk Factors disclosed in our 2015 Form 10-K, except for the following:

The unaudited Condensed Consolidated Financial Statements included herein contain disclosures that express substantial doubt about our ability to continue as a going concern, indicating the possibility that we may not be able to operate in the future.

The unaudited Condensed Consolidated Financial Statements included herein have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. Our liquidity and ability to maintain compliance with debt covenants have been negatively impacted by the prolonged depressed oil and natural gas price environment, levels of indebtedness, and gathering, transportation and certain other commercial contracts. As of September 30, 2016, we had $3.5 million in cash and cash equivalents, $75.4 million of availability under the EXCO Resources Credit Agreement and a working capital deficit of $131.1 million. We have substantial interest payment obligations related to our debt over the next twelve months. The next borrowing base redetermination under the EXCO Resources Credit Agreement is expected to occur in November 2016. The lenders party to the EXCO Resources Credit Agreement have considerable discretion in setting our borrowing base, and we are unable to predict the outcome of any future redeterminations.

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As of September 30, 2016, we were in compliance with the financial covenants under the EXCO Resources Credit Agreement. If we are not able to execute transactions to improve our financial condition, we do not believe we will be able to comply with all of the covenants under the EXCO Resources Credit Agreement or have sufficient liquidity to conduct our business operations based on existing conditions and estimates during the next twelve months. If we become insolvent, investors in our common shares may lose the entire value of their investment in our business.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer repurchases of common shares

The following table details our repurchase of common shares for the three months ended September 30, 2016:

Period	Total Number of Shares Purchased	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions) (1)
July 1, 2016 - July 31, 2016	—	$	—	—	$	192.5
August 1, 2016 - August 31, 2016	—	—		—	192.5
September 1, 2016 - September 30, 2016	—	—		—	192.5
Total	—	$	—	—

(1) On July 19, 2010, we announced a $200.0 million share repurchase program.

Item 6. Exhibits

See “Index to Exhibits” for a description of our exhibits.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		EXCO RESOURCES, INC.
		(Registrant)
Date:	November 2, 2016	/s/ Harold L. Hickey
		Harold L. Hickey
		Chief Executive Officer and President
		(Principal Executive Officer)
		/s/ Brian N. Gaebe
		Brian N. Gaebe
		Chief Accounting Officer and Corporate Controller
		(Principal Accounting Officer)

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INDEX TO EXHIBITS

Exhibit

Number Description of Exhibits

2.1 Haynesville Purchase and Sale Agreement, by and among Chesapeake Louisiana, L.P., Empress, L.L.C., Empress Louisiana Properties, L.P. and EXCO Operating Company, LP, dated July 2, 2013, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2013 filed on October 30, 2013 and incorporated by reference herein.

2.2 Eagle Ford Purchase and Sale Agreement, by and between Chesapeake Exploration, L.L.C. and EXCO Operating Company, LP, dated July 2, 2013, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2013 filed on October 30, 2013 and incorporated by reference herein.

2.3 Contribution Agreement, by and among BG US Gathering Company, LLC, EXCO Operating Company, LP and Azure Midstream Holdings LLC, dated as of October 16, 2013, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated October 16, 2013 and filed on October 22, 2013 and incorporated by reference herein.

2.4 Purchase Agreement, dated October 6, 2014, by and among EXCO Resources, Inc., a Texas corporation, EXCO Operating Company, LP, a Delaware limited partnership, EXCO Holding MLP, Inc., a Texas corporation, HGI Energy Holdings, LLC, a Delaware limited liability company, Compass Production Services, LLC, a Delaware limited liability company, and Compass Energy Operating, LLC, a Delaware limited liability company, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated October 6, 2014 and filed on October 10, 2014 and incorporated by reference herein.

3.1 Amended and Restated Certificate of Formation of EXCO Resources, Inc., as amended through November 16, 2015, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 16, 2015 and filed on November 17, 2015 and incorporated by reference herein.

3.2 Third Amended and Restated Bylaws of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 8, 2015 and filed on September 9, 2015 and incorporated by reference herein.

4.1 Indenture, dated September 15, 2010, by and between EXCO Resources, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.

4.2 First Supplemental Indenture, dated September 15, 2010, by and among EXCO Resources, Inc., certain of its subsidiaries and Wilmington Trust Company, as trustee, including the form of 7.500% Senior Notes due 2018, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.

4.3 Second Supplemental Indenture, dated as of February 12, 2013, by and among EXCO Resources, Inc., EXCO/HGI JV Assets, LLC, EXCO Holding MLP, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 12, 2013 and filed on February 19, 2013 and incorporated by reference herein.

4.4 Third Supplemental Indenture, dated April 16, 2014, by and among EXCO Resources, Inc., certain of its subsidiaries and Wilmington Trust Company, as trustee, including the form of 8.500% Senior Notes due 2022, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 11, 2014 and filed on April 16, 2014 and incorporated by reference herein.

4.5 Fourth Supplemental Indenture, dated May 12, 2014, by and among EXCO Resources, Inc., EXCO Land Company, LLC and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2014 and filed on July 30, 2014 and incorporated by reference herein.

4.6 Fifth Supplemental Indenture, dated November 24, 2015, by and among EXCO Resources, Inc., certain of its subsidiaries, and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated November 24, 2015 and filed on November 25, 2015 and incorporated by reference herein.

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4.7 Sixth Supplemental Indenture, dated August 9, 2016, by and among EXCO Resources, Inc., certain of its subsidiaries, and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated August 9, 2016 and filed on August 10, 2016 and incorporated by reference herein.

4.8 Specimen Stock Certificate for EXCO’s common stock, filed as an Exhibit to EXCO’s Registration Statement on Form S-3, filed on December 17, 2013 and incorporated by reference herein.

4.9 First Amended and Restated Registration Rights Agreement dated as of December 30, 2005, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), filed as an Exhibit to EXCO’s Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935), filed on January 6, 2006 and incorporated by reference herein.

4.10 Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to the 7.0% Cumulative Convertible Perpetual Preferred Stock and the Hybrid Preferred Stock, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

4.11 Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to the Hybrid Preferred Stock, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

4.12 Joinder Agreement to Registration Rights Agreement, dated January 17, 2014, by and among EXCO Resources, Inc. and WLR IV Exco AIV One, L.P., WLR IV Exco AIV Two, L.P., WLR IV Exco AIV Three, L.P., WLR IV Exco AIV Four, L.P., WLR IV Exco AIV Five, L.P., WLR IV Exco AIV Six, L.P., WLR Select Co-Investment XCO AIV, L.P., WLR/GS Master Co-Investment XCO AIV, L.P. and WLR IV Parallel ESC, L.P, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 21, 2014 and incorporated by reference herein.

4.13 Joinder Agreement to Registration Rights Agreement, dated January 17, 2014, by and among EXCO Resources, Inc. and Advent Syndicate 780, Clearwater Insurance Company, Northbridge General Insurance Company, Odyssey Reinsurance Company, Clearwater Select Insurance Company, Riverstone Insurance Limited, Zenith Insurance Company and Fairfax Master Trust Fund, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 21, 2014 and incorporated by reference herein.

10.1 Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*

10.2 Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*

10.3 Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*

10.4 Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated August 4, 2011 and filed on August 10, 2011 and incorporated by reference herein.*

10.5 Form of Restricted Stock Award Agreement for Named Executive Officers for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2015 filed on July 27, 2015 and incorporated by reference herein.*

10.6 Form of Performance-Based Restricted Stock Unit Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 30, 2014 and filed on July 3, 2014 and incorporated by reference herein.*

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10.7 Form of Performance-Based Share Unit Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 1, 2015 and filed on July 8, 2015 and incorporated by reference herein.*

10.8 Form of Performance-Based Share Unit Agreement for Named Executive Officers for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 1, 2015 and filed on July 8, 2015 and incorporated by reference herein.*

10.9 Form of Performance-Based Share Unit Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 1, 2016 and filed on July 6, 2016 and incorporated by reference herein.*

10.10 Form of Performance-Based Share Unit Agreement for Named Executive Officers for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 1, 2016 and filed on July 6, 2016 and incorporated by reference herein.*

10.11 Fourth Amended and Restated EXCO Resources, Inc. Severance Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated March 16, 2011 and filed on March 22, 2011 and incorporated by reference herein.*

10.12 Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*

10.13 Amendment Number One to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Annual Report on Form 10-K (File No. 001-32743) for 2009 filed on February 24, 2010 and incorporated by reference herein.*

10.14 Amendment Number Two to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., effective as of May 22, 2014, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 22, 2014 and filed on May 29, 2014 and incorporated by reference herein.*

10.15 Amendment Number Three to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., effective as of December 4, 2015, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated December 4, 2015 and filed on December 10, 2015 and incorporated by reference herein.*

10.16 Letter Agreement, dated March 28, 2007, with OCM Principal Opportunities Fund IV, L.P. and OCM EXCO Holdings, LLC, filed as an Exhibit to EXCO’s Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

10.17 Amendment Number One to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 4, 2009 and filed on June 10, 2009 and incorporated by reference herein.*

10.18 Amendment Number Two to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, dated as of October 6, 2011, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated October 6, 2011 and filed on October 7, 2011 and incorporated by reference herein.*

10.19 Amendment Number Three to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, dated as of June 11, 2013, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated June 11, 2013 and filed on June 12, 2013 and incorporated by reference herein.*

10.20 Form of Restricted Stock Award Agreement, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2013 filed on August 7, 2013 and incorporated by reference herein.*

10.21 Joint Development Agreement, dated August 14, 2009, by and among BG US Production Company, LLC, EXCO Operating Company, LP and EXCO Production Company, LP, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated August 11, 2009 and filed on August 17, 2009 and incorporated by reference herein.

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10.22 Amendment to Joint Development Agreement, dated February 1, 2011, by and among BG US Production Company, LLC and EXCO Operating Company, LP, filed as an Exhibit to EXCO’s Annual Report on Form 10-K (File No. 001-32743) for 2010 filed February 24, 2011 and incorporated by reference herein.

10.23 Amendment to Joint Development Agreement, dated October 14, 2014, by and among BG US Production Company, LLC and EXCO Operating Company, LP, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2014 filed on February 25, 2015 and incorporated by reference herein.

10.24 Joint Development Agreement, dated as of June 1, 2010, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.25 Amendment to Joint Development Agreement, dated February 4, 2011, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K (File No. 001-32743) for 2010 filed February 24, 2011 and incorporated by reference herein.

10.26 Amendment to Joint Development Agreement, dated October 14, 2014, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2014 filed on February 25, 2015 and incorporated by reference herein.

10.27 Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC, dated June 1, 2010, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.28 Amendment to Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC, dated October 14, 2014, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2014 filed on February 25, 2015 and incorporated by reference herein.

10.29 Second Amended and Restated Limited Liability Company Agreement of Appalachia Midstream, LLC, dated June 1, 2010, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and Appalachia Midstream, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.30 Amendment to Second Amended and Restated Limited Liability Company Agreement of Appalachia Midstream, LLC (n/k/a EXCO Appalachia Midstream, LLC), dated October 14, 2014, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Appalachia Midstream, LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2014 filed on February 25, 2015 and incorporated by reference herein.

10.31 Letter Agreement, dated June 1, 2010 and effective as of May 9, 2010, by and between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.32 Guaranty, dated May 9, 2010, by BG Energy Holdings Limited in favor of EXCO Holding (PA), Inc., EXCO Production Company (PA), LLC and EXCO Production Company (WV), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.33 Performance Guaranty, dated May 9, 2010, by EXCO Resources, Inc. in favor of BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.34 Guaranty, dated June 1, 2010, by BG North America, LLC in favor of (i) EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC

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and EXCO Holding (PA), Inc, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.35 Guaranty, dated June 1, 2010, by EXCO Resources, Inc., in favor of: (i) BG Production Company (PA), LLC, BG Production Company (WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.36 Transition Consulting Agreement, dated February 28, 2013, by and between EXCO Resources, Inc. and Stephen F. Smith, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated February 28, 2013 and filed on March 6, 2013 and incorporated by reference herein.*

10.37 Amended and Restated Credit Agreement, dated as of July 31, 2013, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K, dated as of August 19, 2013 and filed on August 23, 2013 and incorporated by reference herein.

10.38 First Amendment to Amended and Restated Credit Agreement, dated as of August 28, 2013, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated as of August 28, 2013 and filed on September 4, 2013 and incorporated by reference herein.

10.39 Second Amendment to Amended and Restated Credit Agreement, dated as of July 14, 2014, by and among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated as of July 14, 2014 and filed on July 18, 2014 and incorporated by reference herein.

10.40 Third Amendment to Amended and Restated Credit Agreement, dated as of October 21, 2014, by and among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated October 21, 2014 and filed on October 27, 2014 and incorporated by reference herein.

10.41 Fourth Amendment to Amended and Restated Credit Agreement, dated as of February 6, 2015, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated as of February 6, 2015 and filed on February 12, 2015 and incorporated by reference herein.

10.42 Fifth Amendment to Amended and Restated Credit Agreement, dated July 27, 2015, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated as of July 27, 2015 and filed July 28, 2015 and incorporated by reference herein.

10.43 Sixth Amendment to Amended and Restated Credit Agreement, dated as of October 19, 2015, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated as of October 19, 2015 and filed on October 22, 2015 and incorporated by reference herein.

10.44 Limited Consent, dated as of September 1, 2016, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed herewith.

10.45 Term Loan Credit Agreement, dated as of October 19, 2015, by and among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, Hamblin Watsa Investment Counsel Ltd., as Administrative Agent, and Wilmington Trust, National Association, as Collateral Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated as of October 19, 2015 and filed on October 22, 2015 and incorporated by reference herein.

10.46 Term Loan Credit Agreement, dated as of October 19, 2015, by and among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, and Wilmington Trust, National

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Association, as Administrative Agent and Collateral Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated as of October 19, 2015 and filed on October 22, 2015 and incorporated by reference herein.

10.47 Form of Joinder Agreement to Term Loan Credit Agreement, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated as of November 4, 2015 and incorporated by reference herein.

10.48 Intercreditor Agreement, dated as of October 26, 2015, by and among EXCO Resources, Inc., JPMorgan Chase Bank, N.A., as Priority Lien Agent, and Wilmington Trust, National Association, as Second Lien Collateral Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated as of October 26, 2015 and filed on October 27, 2015 and incorporated by reference herein.

10.49 Intercreditor Joinder, dated as of October 26, 2015, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated as of October 26, 2015 and filed on October 27, 2015 and incorporated by reference herein.

10.50 Collateral Trust Agreement, dated as of October 26, 2015, by and among EXCO Resources, Inc., the grantors and guarantors from time to time party thereto, Hamblin Watsa Investment Counsel Ltd., as Administrative Agent of the second lien credit agreement, the other parity lien debt representatives from time to time party thereto, and Wilmington Trust, National Association, as Collateral Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated as of October 26, 2015 and filed on October 27, 2015 and incorporated by reference herein.

10.51 Collateral Trust Joinder, dated as of October 26, 2015, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated as of October 26, 2015 and filed on October 27, 2015 and incorporated by reference herein.

10.52 Form of Purchase Agreement, filed as an Exhibit to EXCO’s Form 8-K, dated as of October 30, 2015 and filed on November 2, 2015 and incorporated by reference herein.

10.53 Form of Follow-on Purchase Agreement, filed as an Exhibit to EXCO’s Form 8-K, dated as of October 19, 2015 and filed on October 22, 2015 and incorporated by reference herein.

10.54 Amended and Restated Participation Agreement, dated July 25, 2016, by and among Admiral A Holding L.P., TE Admiral A Holding L.P., Colt Admiral A Holding L.P. and EXCO Operating Company, LP., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 25, 2016 and filed on July 27, 2016 and incorporated by reference herein.

10.55 Form of Director Indemnification Agreement, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated November 10, 2010 and filed on November 12, 2010 and incorporated by reference herein.

10.56 MVC Letter Agreement, dated November 15, 2013, among BG US Production Company, LLC, BG US Gathering Company, LLC, EXCO Operating Company, LP, Azure Midstream Energy LLC (formerly known as TGGT Holdings, LLC) and TGG Pipeline, Ltd, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 15, 2013 and filed on November 21, 2013 and incorporated by reference herein.

10.57 Letter Agreement, dated March 28, 2014, by and among EXCO Resources, Inc. and Ares Corporate Opportunities Fund, L.P., ACOF EXCO L.P, ACOF EXCO 892 Investors, L.P., Ares Corporate Opportunities Fund II, L.P., Ares EXCO, L.P. and Ares EXCO 892 Investors, L.P., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 27, 2014 and filed on April 1, 2014 and incorporated by reference herein.

10.58 EXCO Resources, Inc. 2014 Management Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 21, 2014 and filed on April 25, 2014 and incorporated by reference herein.*

10.59 Amendment Number One to the EXCO Resources, Inc. Management Incentive Plan, effective as of September 1, 2014, filed as an Exhibit to Amendment No. 1 to EXCO's Current Report on Form 8-K/A, dated August 6, 2014 and filed on September 5, 2014 and incorporated by reference herein.*

10.60 EXCO Resources, Inc. 2015 Management Incentive Plan, dated March 4, 2015, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 4, 2015 and filed on March 10, 2015 and incorporated by reference herein.*

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10.61 EXCO Resources, Inc. 2016 Management Incentive Plan, dated April 20, 2016, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 20, 2016 and filed on April 26, 2016 and incorporated by reference herein.*

10.62 Retention Agreement, dated May 14, 2015, by and between Harold H. Jameson and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 14, 2015 and filed on May 20, 2015 and incorporated by reference herein.*

10.63 Amended and Restated Retention Agreement, dated May 14, 2015, by and between Harold L. Hickey and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 14, 2015 and filed on May 20, 2015 and incorporated by reference herein.*

10.64 Services and Investment Agreement, dated as of March 31, 2015, by and among EXCO Resources, Inc. and Energy Strategic Advisory Services LLC, filed as an Exhibit to Amendment No. 1 to EXCO’s Current Report on Form 8-K/A, dated March 31, 2015 and filed on May 26, 2015 and incorporated by reference herein.

10.65 Acknowledgement of Amendment to Services and Investment Agreement, dated as of May 26, 2015, by and between EXCO Resources, Inc. and Energy Strategic Advisory Services LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 26, 2015 and filed on June 1, 2015 and incorporated by reference herein.

10.66 Amendment No. 2 to Services and Investment Agreement, dated as of September 8, 2015, by and between EXCO Resources, Inc. and Energy Strategic Advisory Services LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 8, 2015 and filed on September 9, 2015 and incorporated by reference herein.

10.67 Nomination Letter Agreement, dates as of September 8, 2015, by and between EXCO Resources, Inc. and Energy Strategic Advisory Services LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 8, 2015 and filed on September 9, 2015 and incorporated by reference herein.

10.68 Warrant, dated as of March 31, 2015, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 31, 2015 and filed on April 2, 2015 and incorporated by reference herein.

10.69 Warrant, dated as of March 31, 2015, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 31, 2015 and filed on April 2, 2015 and incorporated by reference herein.

10.70 Warrant, dated as of March 31, 2015, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 31, 2015 and filed on April 2, 2015 and incorporated by reference herein.

10.71 Warrant, dated as of March 31, 2015, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 31, 2015 and filed on April 2, 2015 and incorporated by reference herein.

10.72 Registration Rights Agreement, dated as of April 21, 2015, by and between EXCO Resources, Inc. and Energy Strategic Advisory Services LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 21, 2015 and filed on April 27, 2015 and incorporated by reference herein.

10.73 Registration Rights Waiver, dated as of April 10, 2015, by and among EXCO Resources, Inc. and Jeffrey D. Benjamin, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 21, 2015 and filed on April 27, 2015 and incorporated by reference herein.

10.74 Registration Rights Waiver, dated as of April 10, 2015, by and among EXCO Resources, Inc. and Robert L. Stillwell, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 21, 2015 and filed on April 27, 2015 and incorporated by reference herein.

10.75 Registration Rights Waiver, dated as of April 10, 2015, by and among EXCO Resources, Inc. and Harold L. Hickey, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 21, 2015 and filed on April 27, 2015 and incorporated by reference herein.

10.76 Registration Rights Waiver, dated as of April 13, 2015, by and among EXCO Resources, Inc. and Advent Capital (No. 3) Limited, Clearwater Insurance Company, Clearwater Select Insurance Company, Fairfax Financial Holdings Master Trust Fund, Northbridge General Insurance Company, Odyssey Reinsurance Company, RiverStone

61

Insurance Limited, Zenith Insurance Company and Hamblin Watsa Investment Counsel, Ltd., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 21, 2015 and filed on April 27, 2015 and incorporated by reference herein.

10.77 Registration Rights Waiver, dated as of April 13, 2015, by and among EXCO Resources, Inc. and OCM EXCO Holdings, LLC, OCM Principal Opportunities Fund IV Delaware, L.P., OCM Principal Opportunities Fund III, L.P., OCM Principal Opportunities Fund IIIA, L.P. and Oaktree Value Opportunities Fund Holdings, L.P., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 21, 2015 and filed on April 27, 2015 and incorporated by reference herein.

10.78 Registration Rights Waiver, dated as of April 21, 2015, by and among EXCO Resources, Inc. and WLR IV Exco AIV One, L.P., WLR IV Exco AIV Two, L.P., WLR IV Exco AIV Three, L.P., WLR IV Exco AIV Four, L.P., WLR IV Exco AIV Five, L.P., WLR IV Exco AIV Six, L.P., WLR Select Co-Investment XCO AIV, L.P., WLR/GS Master Co-Investment XCO AIV, L.P. and WLR IV Parallel ESC, L.P., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 21, 2015 and filed on April 27, 2015 and incorporated by reference herein.

31.1  Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Principal Executive Officer of EXCO Resources, Inc., filed herewith.

31.2  Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Principal Financial Officer of EXCO Resources, Inc., filed herewith.

32.1  Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Principal Executive Officer and Principal Financial Officer of EXCO Resources, Inc., filed herewith.

101.INS XBRL Instance Document.

101.SCH XBRL Taxonomy Extension Schema Document.

101.CAL XBRL Taxonomy Calculation Linkbase Document.

101.DEF XBRL Taxonomy Definition Linkbase Document.

101.LAB XBRL Taxonomy Label Linkbase Document.

101.PRE XBRL Taxonomy Presentation Linkbase Document.

* These exhibits are management contracts.

62

EX-10.44

Exhibit 10.44

September 1, 2016

EXCO Resources, Inc.

12377 Merit Drive

Suite 1700

Dallas, Texas 75251

Attention: Chief Financial Officer

Re:    Limited Consent

Ladies and Gentleman:

Reference is hereby made to that certain Amended and Restated Credit Agreement, dated as of July 31, 2013, among EXCO Resources, Inc., a Texas corporation, as the Borrower, certain Subsidiaries of the Borrower, as Guarantors, the lenders from time to time party thereto (the “Lenders”) and JPMorgan Chase Bank, N.A., as administrative agent for the Lenders (in such capacity, the “Administrative Agent”) (as the same may be amended, restated, amended and restated, supplemented or otherwise modified from time to time, the “Credit Agreement”). Capitalized terms used and not otherwise defined herein shall have the meanings given such terms in the Credit Agreement. References herein to any Section shall be to a Section of the Credit Agreement unless otherwise specifically provided.

Pursuant to Sections 3.02, 3.03, and 3.04, the next Scheduled Redetermination of the Borrowing Base shall occur on or about September 1, 2016. The Borrower has requested that the Scheduled Redetermination to occur on or about September 1, 2016 be postponed until November 1, 2016. Subject to the terms and conditions described herein, the Administrative Agent and the Lenders (or at least the required percentage thereof) are willing to postpone the Scheduled Redetermination to occur on or about September 1, 2016 until November 1, 2016 (the “Postponed Redetermination”).

The Borrower has also informed the Administrative Agent that the Credit Parties desire to offer the Borrowing Base Properties generally described on Schedule I attached hereto for sale (collectively, the “Specified Properties” and each, a “Specified Property”), and that the Credit Parties expect such sales to occur prior to the postponed Scheduled Redetermination requested by Borrower above. Section 7.03(a)(vii) prohibits the sale, transfer or other Disposition of Borrowing Base Properties by the Credit Parties unless the Engineered Value of all Borrowing Base Properties sold, transferred or otherwise Disposed of between Scheduled Redeterminations does not exceed five percent (5%) of the Borrowing Base most recently determined. In connection with such proposed sales, the Borrower has requested, to the extent required under the Credit Agreement, that the Administrative Agent and the Lenders (or at least the required percentage thereof) consent to the sale of each Specified Property. Subject to the terms and conditions described herein, to the extent required under the Credit Agreement, the

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent – Page 1

Administrative Agent and the Lenders (or at least the required percentage thereof) are willing to consent to the sale, transfer or other Disposition of the Specified Properties.

Accordingly, subject to the terms and conditions set forth below, and in reliance on the representations, warranties, acknowledgments and agreements contained herein, the Administrative Agent and the Lenders (or at least the required percentage thereof) hereby consent and agree to:

(a)    the Postponed Redetermination; provided that, from and after the date hereof and until the date such Postponed Redetermination becomes effective, (i) the Borrower shall not request that (A) the Lenders make any Loans and/or (B) the Issuing Bank issue, amend, renew or extend any Letter of Credit, if at the time of and immediately after giving effect to such Borrowing or issuance, amendment, renewal or extension of such Letter of Credit, as applicable, the Aggregate Revolving Credit Exposure would exceed $300,000,000 and (ii) Borrower and the other Credit Parties agree that any request made in violation of clause (i) above shall be null and void and Lenders shall not be obligated to make any Loans and the Issuing Bank shall not be obligated to issue, amend, renew or extend any Letter of Credit pursuant to any such request; providedfurther, that notwithstanding the foregoing, the Borrower shall be permitted to use the existing Borrowing Base amount of $325,000,000 for purposes of calculating the Consolidated Current Ratio for the fiscal quarter ending September 30, 2016; and

(b)    the sale, transfer or other Disposition of each Specified Property, notwithstanding the restrictions contained in Section 7.03(a)(vii); provided that:

(i)    the sale of such Specified Property is consummated prior to November 1, 2016;

(ii)    on the date such sale is consummated, no Default or Event of Default has occurred and is continuing or would result from such sale;

(iii)    the consideration received in respect of such sale shall be equal to or greater than the fair market value of such Specified Property (as reasonably determined by the chief executive officer or the president (pursuant to authority provided for in the Organizational Documents of the Borrower or under separate authorizing resolutions of the Board of Directors of the Borrower) or the Board of Directors of the Borrower, and if requested by the Administrative Agent or the Required Lenders, the Borrower shall deliver a certificate of a Responsible Officer certifying to that effect); and

(iv)    one hundred percent (100%) of the consideration received from such sale shall be in the form of cash or Permitted Investments.

As consideration for the agreements set forth herein, the Borrower hereby agrees to pay to J.P. Morgan Securities LLC (“J.P. Morgan”) for the account of each Lender that executes this limited consent before 2:00 p.m. (Dallas, Texas time) on Thursday, September 1, 2016 (each such Lender a “Consenting Lender”), a consent fee in an amount equal to the sum of 10 basis points

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent – Page 2

of each Consenting Lender’s Commitment, which consent fee shall be due and payable on the effective date of this limited consent and shall be allocated to the Consenting Lenders based on their Applicable Percentage on the date hereof.

The entire amount of the fees payable hereunder will be fully earned upon becoming due and payable in accordance with the terms hereof. All fees payable hereunder shall be paid in immediately available funds and shall be in addition to reimbursement of our out-of-pocket expenses and any other fees specified in the Credit Agreement and the other Loan Documents. The Borrower agrees that, once paid, the fees or any part thereof payable hereunder shall not be refundable under any circumstances. The Borrower agrees that J.P. Morgan may share the fees payable hereunder with the other Lenders as set forth above.

By its signature below, each Credit Party agrees that, except as expressly set forth above, nothing herein shall be construed as (a) a consent or agreement to, a waiver or continuing waiver of or a modification of any of the provisions of the Credit Agreement or any other Loan Documents, including Sections 3.02, 3.03, 3.04 or7.03(a)(vii), (b) a consent by the Lenders to allow the Borrower or any other Credit Party to sell, transfer or otherwise dispose of any other Borrowing Base Properties under Section 7.03(a)(vii) other than as expressly permitted under the Credit Agreement, or (c) a waiver of any Default or Event of Default now existing or hereafter arising under the Credit Agreement or any other Loan Document. The consent set forth herein is expressly limited as follows: (x) such consent is limited solely to the postponement of the Scheduled Redetermination and sale of the Specified Properties, and (y) such consent is a limited one-time consent, and nothing contained herein shall obligate the Lenders to grant any additional or future consent, or to grant (i) any waiver of Sections 3.02, 3.03, 3.04 or7.03(a)(vii) or any other provision of the Credit Agreement or any other Loan Document or (ii) any waiver of any Default or Event of Default now existing or hereafter arising under the Credit Agreement or any other Loan Document.

By its signature below, each Credit Party hereby (a) acknowledges and agrees that the Credit Agreement and the other Loan Documents are hereby ratified and confirmed in all respects and shall remain in full force and effect; (b) ratifies and reaffirms its obligations under, and acknowledges, renews and extends its continued liability under, the Credit Agreement and each other Loan Document to which it is a party; (c) ratifies and reaffirms all of the Liens securing the payment and performance of the Obligations; (d) represents and warrants to the Administrative Agent and the Lenders that, as of the date hereof, (i) all of the representations and warranties contained in the Credit Agreement and each Loan Document to which it is a party are true and correct in all material respects, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct in all material respects as of such specified earlier date, and (ii) no Default or Event of Default has occurred and is continuing and (e) acknowledges and agrees that this letter agreement shall constitute a Loan Document for all purposes and in all respects.

This limited consent shall become effective as of the date first written above when and only when the Administrative Agent shall have received duly executed counterparts of this limited consent signed by each Credit Party and the Lenders (or at least the required percentage thereof).

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent – Page 3

This limited consent shall be governed by, and construed and interpreted in accordance with, the laws of the State of New York. This limited consent may be executed in counterparts with each counterpart constituting an original and all of the counterparts, once executed, constituting but one original. Delivery of an executed counterpart by facsimile or other electronic means shall be effective as delivery of an original executed counterpart.

[Signature Pages Follow]

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent – Page 4

If the foregoing is acceptable to you, please execute a copy of this limited consent in the spaces provided below to evidence your acceptance and approval of the foregoing and return a fully-executed counterpart of this limited consent to the attention of the undersigned.

Very truly yours,

JPMORGAN CHASE BANK, N.A.,

as Administrative Agent and a Lender

By: /s/ David Morris                

Name:    David Morris

Title:    Authorized Officer

J.P. MORGAN SECURITIES LLC,

as Sole Bookrunner and Co-Lead Arranger

By: /s/ Catherine O'Donnell            

Name:    Catherine O’Donnell

Title:    Authorized Officer

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent

Signature Page

BMO HARRIS BANK N.A.,as a Lender

By:    /s/ James V. Ducote            
Name: James V. Ducote
Title: Managing Director

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent

Signature Page

UBS AG, STAMFORD BRANCH,as a Lender

By:    /s/ Craig Pearson                
Name: Craig Pearson
Title: Associate Director

By:    /s/ Darlene Arias                
Name: Darlene Arias        
Title: Director

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent

Signature Page

CREDIT SUISSE AG, Cayman Islands Branch,as a Lender

By:    /s/ Michael A. Criscito            
Name: Michael A. Criscito
Title: Authorized Signatory

By:    /s/ Julia Bykhovskaia                
Name: Julia Bykhovskaia
Title: Authorized Signatory

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent

Signature Page

NATIXIS,as a Lender

By:    /s/ Brice Le Foyer                
Name: Brice Le Foyer
Title: Director

By:    /s/ Vikram Nath                
Name: Vikram Nath
Title: Vice President

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent

Signature Page

DEUTSCHE BANK AG NEW YORK BRANCH,as a Lender

By:    /s/ Dusan Lazarov                
Name: Dusan Lazarov
Title: Director

By:    /s/ Peter Cucchiara                
Name: Peter Cucchiara
Title: Vice President

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent

Signature Page

GOLDMAN SACHS BANK USA,as a Lender

By:    /s/ Mehmet Barlas                
Name: Mehmet Barlas
Title: Authorized Signatory

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent

Signature Page

CAPITAL ONE, NATIONAL ASSOCIATION,
as a Lender

By:    /s/ Daryl Stafford                
Name: Daryl Stafford
Title: Vice President

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent

Signature Page

CIT FINANCE LLC, as a Lender

By:    /s/ Katya Evseev                
Name: Katya Evseev
Title: Vice President

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent

Signature Page

ING CAPITAL LLC, as a Lender

By:    /s/ Charles Hall                
Name: Charles Hall
Title: Managing Director

By:    /s/ Josh Strong                 
Name: Josh Strong
Title: Director

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent

Signature Page

ACCEPTED AND AGREED TO:

BORROWER:

EXCO RESOURCES, INC.

By: /s/ Christopher C. Peracchi

Name: Christopher C. Peracchi

Title: Vice President, acting Chief Financial Officer and Treasurer

GUARANTORS:

EXCO HOLDING (PA), INC.
EXCO PRODUCTION COMPANY (PA), LLC
EXCO PRODUCTION COMPANY (WV), LLC
EXCO RESOURCES (XA), LLC
EXCO SERVICES, INC.
EXCO MIDCONTINENT MLP, LLC
EXCO PARTNERS GP, LLC
EXCO PARTNERS OLP GP, LLC
EXCO HOLDING MLP, INC.

EXCO LAND COMPANY, LLC

By: /s/ Christopher C. Peracchi

Name: Christopher C. Peracchi

Title: Vice President, acting Chief Financial Officer and Treasurer

EXCO OPERATING COMPANY, LP

By:     EXCO Partners OLP GP, LLC,     its general partner

By: /s/ Christopher C. Peracchi

Name: Christopher C. Peracchi

Title: Vice President, acting Chief Financial Officer and Treasurer

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent

Signature Page

EXCO GP PARTNERS OLD, LP

By:    EXCO Partners GP, LLC,    its general partner

By: /s/ Christopher C. Peracchi

Name: Christopher C. Peracchi

Title: Vice President, acting Chief Financial Officer and Treasurer

RAIDER MARKETING, LP

By:    Raider Marketing GP, LLC,     its general partner

By: /s/ Steven L. Estes

Name: Steven L. Estes

Title: President

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent

Signature Page

Schedule I

Specified Properties

See attached.

JPMorgan Chase Bank, N.A. – EXCO – Limited Consent

Schedule I

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Harold L. Hickey, the Principal Executive Officer of EXCO Resources, Inc., certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of EXCO Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 2, 2016	/s/ Harold L. Hickey
		Harold L. Hickey
		Chief Executive Officer and President

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Christopher C. Peracchi, the Principal Financial Officer of EXCO Resources, Inc., certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of EXCO Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 2, 2016	/s/ Christopher C. Peracchi
		Christopher C. Peracchi
		Chief Financial Officer, Vice President and Treasurer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), each of the undersigned officers of EXCO Resources, Inc. (the “Company”) in their capacity as Principal Executive Officer and Principal Financial Officer, respectively, does hereby certify, to such officer’s knowledge, that:

The Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 (the “Form 10-Q”) of the Company fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended, and the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company as of, and for, the periods presented in the Form 10-Q.

Date:	November 2, 2016	/s/ Harold L. Hickey
		Harold L. Hickey
		Chief Executive Officer and President
		/s/ Christopher C. Peracchi
		Christopher C. Peracchi
		Chief Financial Officer, Vice President and Treasurer

The foregoing certification is being furnished as an exhibit to the Form 10-Q pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Form 10-Q for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

XML

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 28, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Entity Registrant Name	EXCO RESOURCES INC
Entity Central Index Key	0000316300
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		282,445,821

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 3,534	$ 12,247
Restricted cash	18,434	21,220
Accounts receivable, net:
Oil and natural gas	53,439	37,236
Joint interest	17,949	22,095
Other	3,871	8,894
Derivative financial instruments	5,952	39,499
Inventory and other	7,630	8,610
Total current assets	110,809	149,801
Equity investments	31,973	40,797
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	93,511	115,377
Proved developed and undeveloped oil and natural gas properties	2,946,641	3,070,430
Accumulated depletion	(2,690,611)	(2,627,763)
Oil and natural gas properties, net	349,541	558,044
Other property and equipment, net	24,058	27,812
Deferred financing costs, net	5,000	8,408
Derivative financial instruments	1,455	6,109
Goodwill	163,155	163,155
Total assets	685,991	954,126
Current liabilities:
Accounts payable and accrued liabilities	56,056	88,049
Revenues and royalties payable	121,312	106,163
Accrued interest payable	3,774	7,846
Current portion of asset retirement obligations	428	845
Income taxes payable	0	0
Derivative financial instruments	10,353	16
Current maturities of long-term debt	50,000	50,000
Total current liabilities	241,923	252,919
Long-term debt	1,256,068	1,320,279
Deferred income taxes	1,775	0
Derivative financial instruments	1,189	0
Asset retirement obligations and other long-term liabilities	22,626	43,251
Shareholders’ equity:
Common shares, $0.001 par value; 780,000,000 authorized shares; 283,040,484 shares issued and 282,445,821 shares outstanding at September 30, 2016; 283,633,996 shares issued and 283,039,333 shares outstanding at December 31, 2015	283	276
Additional paid-in capital	3,537,393	3,522,153
Accumulated deficit	(4,367,634)	(4,177,120)
Treasury shares, at cost; 594,663 shares at September 30, 2016 and December 31, 2015	(7,632)	(7,632)
Total shareholders' equity	(837,590)	(662,323)
Total liabilities and shareholders' equity	$ 685,991	$ 954,126

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.001	$ 0.001
Common stock, authorized shares	780,000,000	780,000,000
Common stock, shares issued	283,040,484	283,633,996
Common stock, shares outstanding	282,445,821	283,039,333
Treasury stock, shares	594,663	594,663

XML

Consolidated Statements Of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues:
Oil	$ 16,215	$ 27,444	$ 49,688	$ 79,872
Natural gas	54,647	56,300	127,044	184,275
Purchased natural gas and marketing	6,324	6,773	15,335	21,012
Total revenues	77,186	90,517	192,067	285,159
Costs and expenses:
Oil and natural gas operating costs	8,797	12,669	25,835	41,745
Production and ad valorem taxes	3,811	5,944	13,308	16,408
Gathering and transportation	27,979	23,743	79,828	74,243
Purchased natural gas	6,586	6,991	17,273	21,571
Depletion, depreciation and amortization	15,910	52,013	63,995	176,160
Impairment of oil and natural gas properties	0	339,393	160,813	1,010,047
Accretion of discount on asset retirement obligations	325	574	2,006	1,698
General and administrative	10,746	13,393	38,626	41,227
Other operating items	(1,110)	(228)	23,936	1,118
Total costs and expenses	73,044	454,492	425,620	1,384,217
Operating income (loss)	4,142	(363,975)	(233,553)	(1,099,058)
Other income (expense):
Interest expense, net	(16,997)	(27,761)	(54,186)	(80,822)
Gain (loss) on derivative financial instruments	8,209	37,348	(11,632)	54,427
Gain on extinguishment of debt	57,421	0	119,374	0
Other income	12	21	37	119
Equity loss	(823)	(152)	(8,824)	(1,452)
Total other income (expense)	47,822	9,456	44,769	(27,728)
Income (loss) before income taxes	51,964	(354,519)	(188,784)	(1,126,786)
Income tax expense	1,028	0	1,775	0
Net income (loss)	$ 50,936	$ (354,519)	$ (190,559)	$ (1,126,786)
Basic:
Net income (loss) (in dollars per share)	$ 0.18	$ (1.30)	$ (0.68)	$ (4.14)
Weighted average common shares outstanding	279,873	273,348	279,008	272,147
Diluted:
Net income (loss) (in dollars per share)	$ 0.18	$ (1.30)	$ (0.68)	$ (4.14)
Weighted average common shares and common share equivalents outstanding	281,045	273,348	279,008	272,147

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Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Operating Activities:
Net loss	$ (190,559)	$ (1,126,786)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Deferred income tax expense	1,775	0
Depletion, depreciation and amortization	63,995	176,160
Equity-based compensation expense	14,558	4,045
Accretion of discount on asset retirement obligations	2,006	1,698
Impairment of oil and natural gas properties	160,813	1,010,047
Loss from equity investments	8,824	1,452
(Gain) loss on derivative financial instruments	11,632	(54,427)
Cash receipts of derivative financial instruments	38,097	88,977
Amortization of deferred financing costs and discount on debt issuance	7,250	11,083
Other non-operating items	24,068	(13)
Gain on extinguishment of debt	(119,374)	0
Effect of changes in:
Restricted cash with related party	2,100	(1,500)
Accounts receivable	(12,752)	59,238
Other current assets	(1,207)	1,062
Accounts payable and other current liabilities	(14,966)	(44,180)
Net cash provided by (used in) operating activities	(3,740)	126,856
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment	(70,455)	(269,708)
Property acquisitions	0	(7,608)
Proceeds from disposition of property and equipment	11,242	7,397
Restricted cash	686	4,016
Net changes in advances to joint ventures	2,377	8,594
Equity investments and other	0	1,455
Net cash used in investing activities	(56,150)	(255,854)
Financing Activities:
Borrowings under EXCO Resources Credit Agreement	390,897	97,500
Repayments under EXCO Resources Credit Agreement	(243,797)	0
Payments on Exchange Term Loan	(38,056)	0
Repurchases of senior unsecured notes	(53,298)	0
Proceeds from issuance of common shares, net	0	9,829
Deferred financing costs and other	(4,569)	(4,125)
Net cash provided by financing activities	51,177	103,204
Net decrease in cash	(8,713)	(25,794)
Cash at beginning of period	12,247	46,305
Cash at end of period	3,534	20,511
Supplemental Cash Flow Information:
Cash interest payments	51,975	81,913
Income tax payments	0	0
Supplemental non-cash investing and financing activities:
Capitalized equity-based compensation	432	2,861
Capitalized interest	$ 3,939	$ 10,121

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Consolidated Statements Of Changes In Shareholders' Equity - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Treasury Stock	Additional paid-in capital	Accumulated deficit
Beginning Balance (in shares) at Dec. 31, 2014		274,352	(578)
Beginning Balance at Dec. 31, 2014	$ 510,004	$ 270	$ (7,615)	$ 3,502,209	$ (2,984,860)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock	9,881	$ 6		9,875
Issuance of common stock (in shares)		5,882
Equity-based compensation	6,439			6,439
Restricted stock issued, net of cancellations (in shares)		3,422
Restricted stock issued, net of cancellations	0	$ 0
Common stock dividends	3				3
Treasury Stock, Shares, Acquired			(17)
Treasury Stock, Value, Acquired, Cost Method	(17)		$ (17)
Net loss	(1,126,786)				(1,126,786)
Ending Balance at Sep. 30, 2015	(600,476)	$ 276	$ (7,632)	3,518,523	(4,111,643)
Ending Balance (in shares) at Sep. 30, 2015		283,656	(595)
Beginning Balance (in shares) at Dec. 31, 2015		283,634	(595)
Beginning Balance at Dec. 31, 2015	(662,323)	$ 276	$ (7,632)	3,522,153	(4,177,120)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock	0
Issuance of common stock (in shares)		243
Equity-based compensation	15,240			15,240
Restricted stock issued, net of cancellations (in shares)		(837)
Restricted stock issued, net of cancellations	7	$ 7
Common stock dividends	45				45
Net loss	(190,559)				(190,559)
Ending Balance at Sep. 30, 2016	$ (837,590)	$ 283	$ (7,632)	$ 3,537,393	$ (4,367,634)
Ending Balance (in shares) at Sep. 30, 2016		283,040	(595)

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Organization And Basis Of Presentation

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and basis of presentation

Organization and basis of presentation

Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” are to EXCO Resources, Inc. and its consolidated subsidiaries.

We are an independent oil and natural gas company engaged in the exploration, exploitation, acquisition, development and production of onshore U.S. oil and natural gas properties with a focus on shale resource plays. Our principal operations are conducted in certain key U.S. oil and natural gas areas including Texas, Louisiana and the Appalachia region. The following is a brief discussion of our producing regions.

•East Texas and North Louisiana

The East Texas and North Louisiana regions are primarily comprised of our Haynesville and Bossier shale assets. We have a joint venture with BG Group, plc ("BG Group"), a wholly owned subsidiary of Royal Dutch Shell, plc, covering an undivided 50% interest in the majority of our Haynesville and Bossier shale assets in East Texas and North Louisiana. The East Texas and North Louisiana regions also include certain assets outside of the joint venture in the Haynesville and Bossier shales. We serve as the operator for most of our properties in the East Texas and North Louisiana regions.

•South Texas

The South Texas region is primarily comprised of our Eagle Ford shale assets. We serve as the operator for most of our properties in the South Texas region.

•Appalachia

The Appalachia region is primarily comprised of Marcellus shale assets as well as shallow conventional assets in other formations. We have a joint venture with BG Group covering our 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. On July 1, 2016, we closed the sale of our interests in shallow conventional assets located in Pennsylvania and retained an overriding royalty interest in each well, and on October 3, 2016, we closed the sale of our interests in shallow conventional assets located in West Virginia. See "Note 3. Divestitures" for additional discussion.

The accompanying Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015, Condensed Consolidated Statements of Operations for the three and nine months endedSeptember 30, 2016 and 2015, Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the nine months endedSeptember 30, 2016 and 2015 are for EXCO and its subsidiaries. The unaudited Condensed Consolidated Financial Statements and related footnotes are presented in accordance with generally accepted accounting principles in the United States ("GAAP"). Certain reclassifications have been made to prior period information to conform to current period presentation.

We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") and in the opinion of management, such financial statements reflect all adjustments necessary to fairly present the consolidated financial position of EXCO at September 30, 2016 and its results of operations and cash flows for the periods presented. We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with GAAP pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. These unaudited interim financial statements should be read in conjunction with our audited consolidated financial statements and related footnotes included in EXCO's Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on March 2, 2016 ("2015 Form 10-K").

In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures. The results of operations for the interim periods are not necessarily indicative of the results we expect for the full year.

Going Concern Presumption and Management’s Plans

These unaudited Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. Our liquidity and ability to maintain compliance with debt covenants have been negatively impacted by the prolonged depressed oil and natural gas price environment, levels of indebtedness, and gathering, transportation and certain other commercial contracts. As of September 30, 2016, the Company had $3.5 million in cash and cash equivalents, $75.4 million of availability under its credit agreement ("EXCO Resources Credit Agreement") and a working capital deficit of $131.1 million. We have substantial interest payment obligations related to our debt over the next twelve months. The next borrowing base redetermination under the EXCO Resources Credit Agreement is expected to occur in November 2016. The lenders party to the EXCO Resources Credit Agreement have considerable discretion in setting our borrowing base, and we are unable to predict the outcome of any future redeterminations.

Our plans to improve near-term liquidity primarily include the issuance of additional indebtedness and we are engaged in discussions with potential lenders. The availability and terms of this financing may be dependent upon our ability to reduce fixed commitments including gathering and transportation contracts. We continue to negotiate a consensual restructuring of gathering and transportation contracts with our counterparties. If we are not able to execute transactions to improve our financial condition, we do not believe we will be able to comply with all of the covenants under the EXCO Resources Credit Agreement or have sufficient liquidity to conduct our business operations based on existing conditions and estimates during the next twelve months. Management’s plans are intended to mitigate these conditions; however, our ability to execute these plans is conditioned upon factors including the availability of capital markets, market conditions, and the actions of counterparties. There is no assurance any such transactions will occur.  

As of September 30, 2016, we were in compliance with the financial covenants under the EXCO Resources Credit Agreement. We are required to 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, which includes unused commitments in the definition of consolidated current assets. The inclusion of the unused commitments has historically allowed us to maintain compliance with the Consolidated Current Ratio covenant under the EXCO Resources Credit Agreement. Therefore, the reduction in unused commitments as a result of borrowings under the EXCO Resources Credit Agreement or further reductions to our borrowing base as part of the redetermination process will negatively impact our Consolidated Current Ratio and liquidity.

The EXCO Resources Credit Agreement does not permit our ratio of senior secured indebtedness to consolidated EBITDAX ("Senior Secured Indebtedness Ratio") to be greater than 2.5 to 1.0 as of the end of any fiscal quarter. Senior secured indebtedness utilized in the Senior Secured Indebtedness Ratio excludes the Second Lien Term Loans (as defined below) and any other secured indebtedness subordinated to the EXCO Resources Credit Agreement. The Company's compliance with this covenant will be negatively impacted unless we are able to increase our EBITDAX, generate positive free cash flows and/or find other sources of capital to reduce indebtedness under the EXCO Resources Credit Agreement.

As a result of the impact of the aforementioned factors on our financial results and condition, we anticipate that we will not meet the minimum requirement under the Consolidated Current Ratio and the Senior Secured Indebtedness Ratio for the twelve-month period following the date of these unaudited Condensed Consolidated Financial Statements. We may not be in compliance with these covenants as early as the fiscal quarter ending December 31, 2016 depending on our future financial and operating results and the outcome of the borrowing base redetermination process. Furthermore, our liquidity is not expected to be sufficient to conduct our business operations for the twelve-month period following the date of these unaudited Condensed Consolidated Financial Statements. If we are not able to comply with our debt covenants or do not have sufficient liquidity to conduct our business operations in future periods, we may be required, but unable, to refinance all or part of our existing debt, seek covenant relief from our lenders, sell assets, incur additional indebtedness, or issue 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. Therefore, our ability to continue our planned principal business operations would be dependent on the actions of our lenders or obtaining additional debt and/or equity financing to repay outstanding indebtedness under the EXCO Resources Credit Agreement. These factors raise substantial doubt about our ability to continue as a going concern.

The EXCO Resources Credit Agreement and the term loan credit agreements governing our senior secured second lien term loans due October 26, 2020 (“Second Lien Term Loans”) require our annual financial statements to include a report from our independent registered public accounting firm without an explanatory paragraph related to our ability to continue as a going concern. If the substantial doubt about our ability to continue as a going concern still exists at December 31, 2016 or if we fail to comply with the financial and other covenants in the EXCO Resources Credit Agreement or the Second Lien Term Loans, we would be in default under such agreement. Any event of default may cause a default or accelerate our obligations with respect to our other outstanding indebtedness, including our senior unsecured notes due September 15, 2018 (“2018 Notes”) and senior unsecured notes due April 15, 2022 (“2022 Notes”), which could adversely affect our business, financial condition and results of operations.

The accompanying unaudited Condensed Consolidated Financial Statements do not include any adjustments to reflect the possible future effects of this uncertainty on the recoverability or classification of recorded asset amounts or the amounts or classification of liabilities.

Revisions of prior period information

On August 19, 2016, we formed Raider Marketing, LP ("Raider") through an internal merger to provide marketing services to EXCO and pursue independent business opportunities. Raider is a wholly owned subsidiary of EXCO and is the contractual counterparty by operation of Texas law to all of EXCO's gathering, transportation and marketing contracts in Texas and Louisiana. In connection with the formation of Raider and the Company's plans to pursue additional marketing opportunities, we have revised our presentation of third party natural gas purchases and sales to report these costs and revenues on a gross basis in the accompanying statements of operations in accordance with Financial Accounting Standards Board (“FASB”) Codification (“ASC”) 605, Revenue Recognition, beginning in the third quarter of 2016. Third party purchases and sales are now reported gross as "Purchased natural gas" expenses and "Purchased natural gas and marketing" revenues, respectively. Purchased natural gas and marketing revenues include revenue we receive as a result of selling natural gas that we purchase from third parties and marketing fees we receive from third parties. Purchased natural gas expenses include purchases from third parties plus an allocation of transportation costs. The transportation costs allocated to the third party purchases relate to our firm transportation agreements with unutilized commitments; therefore, the utilization of this transportation reduces the unutilized commitments that would have otherwise been allocated to our net share of production and incurred by EXCO.

We previously reported these transactions on a net basis in the financial statements due to the materiality associated with the income or loss generated from these purchases and sales, and the historical insignificance of the Company's marketing activities involving the purchases and sales of third party natural gas to our business strategies and operations. The net effect of these revisions did not impact our previously reported net income or loss, shareholders’ equity or cash flows. The Company evaluated the materiality of the revisions based on ASC 250, Accounting Changes and Error Corrections, and concluded the revisions to be immaterial corrections of an error.

The following table reflects the revisions to prior periods:

					Three months ended
(in thousands)					June 30, 2016			March 31, 2016
Gathering and transportation, previously reported					$	26,895		$	26,630
Revision of third party natural gas purchases and sales					(151		)	(1,525		)
Gathering and transportation, as currently reported					$	26,744		$	25,105
Purchased natural gas and marketing revenues					$	4,570		$	4,441
Purchased natural gas expenses					$	4,721		$	5,966
	Three months ended
(in thousands)	December 31, 2015		September 31, 2015		June 30, 2015			March 31, 2015
Natural gas revenues, previously reported	$	41,828	$	56,082	$	62,197		$	65,437
Revision of third party natural gas purchases and sales	368		218		184			157
Natural gas revenues, as currently reported	$	42,196	$	56,300	$	62,381		$	65,594
Purchased natural gas and marketing revenues	$	5,430	$	6,773	$	6,678		$	7,561
Purchased natural gas expenses	$	5,798	$	6,991	$	6,862		$	7,718

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Summary Of Significant Accounting Policies

9 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Significant accounting policies

Significant accounting policies

We consider significant accounting policies to be those related to our estimates of proved reserves, oil and natural gas properties, derivatives, business combinations, equity-based compensation, goodwill, revenue recognition, asset retirement obligations and income taxes. The policies include significant estimates made by management using information available at the time the estimates were made. However, these estimates could change materially if different information or assumptions were used. These policies and others are summarized in our 2015 Form 10-K.

Recent accounting pronouncements

In August 2016, the FASB issued Accounting Standards Update ("ASU") No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments ("ASU 2016-15"). ASU 2016-15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows. The amendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees. ASU 2016-15 is effective for annual and interim periods beginning after December 15, 2017. We are currently assessing the potential impact of ASU 2016-15 on our consolidated financial condition and results of operations.

In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients ("ASU 2016-12"). ASU 2016-12 does not change the core principle of Topic 606 but improves the following aspects of Topic 606: assessing collectability, presentation of sales taxes, noncash considerations, completed contracts and contract modifications at transaction. ASU 2016-12 is effective for annual and interim periods beginning after December 15, 2017. We are currently assessing the potential impact of ASU 2016-12 on our consolidated financial condition and results of operations.

In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting ("ASU 2016-11"). The SEC Staff is rescinding the following SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. Specifically, registrants should not rely on the following SEC Staff Observer comments upon adoption of Topic 606: a) Revenue and Expense Recognition for Freight Services in Process which is codified in 605-20-S99-2; b) Accounting for Shipping and Handling Fees and Costs, which is codified in paragraph 605-45-S99-1; c) Accounting for Consideration Given by a Vendor to a Customer, which is codified in paragraph 605-50-S99-1 and d) Accounting for Gas-Balancing Arrangements (that is, use of the “entitlements method”), which is codified in paragraph 932-10-S99-5. We do not use the entitlements method of accounting and are not impacted by this specific SEC Staff Observer comment; however, we are assessing the potential impact of other SEC Staff Observer comments included in ASU 2016-11 on our consolidated financial condition and results of operations.

In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing ("ASU 2016-10"). ASU 2016-10 does not change the core principle of Topic 606 but clarifies the following two aspects of Topic 606: identifying performance obligations and the licensing implementation guidance, while retaining the related principles for those areas. ASU 2016-10 is effective for annual and interim periods beginning after December 15, 2017. We are currently assessing the potential impact of ASU 2016-10 on our consolidated financial condition and results of operations.

In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting ("ASU 2016-09"). ASU 2016-09 simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. ASU 2016-07 is effective for annual and interim periods beginning after December 15, 2016 and early adoption is permitted. We are currently assessing the potential impact of ASU 2016-09 on our consolidated financial condition and results of operations.

In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) ("ASU 2016-08"). ASU 2016-08 does not change the core principle of Topic 606 but clarifies the implementation guidance on principal versus agent considerations. ASU 2016-08 is effective for annual and interim periods beginning after December 15, 2017. We are currently assessing the potential impact of ASU 2016-08 on our consolidated financial condition and results of operations.

In March 2016, the FASB issued ASU No. 2016-07, Investments - Equity Method and Joint Ventures (Topic 323): Simplifying the Transition to the Equity Method of Accounting ("ASU 2016-07"). ASU 2016-07 eliminates the requirement that when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence, an investor must adjust the investment, results of operations, and retained earnings retroactively on a step-by-step basis as if the equity method had been in effect during all previous periods that the investment had been held. Therefore, upon qualifying for the equity method of accounting, no retroactive adjustment of the investment is required. ASU 2016-07 is effective for annual and interim periods beginning after December 15, 2016 and early adoption is permitted. We do not currently have significant investments that are accounted for by a method other than the equity method and do not expect ASU 2016-07 to have a significant impact on our consolidated financial condition and results of operations.

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Divestitures Divestitures

9 Months Ended

Sep. 30, 2016

Disposal Group, Not Discontinued Operation, Disposal Disclosures [Abstract]

Mergers, Acquisitions and Dispositions Disclosures [Text Block]

Divestitures

South Texas transaction

On May 6, 2016, we closed a sale of certain non-core undeveloped acreage in South Texas and our interests in four producing wells for $11.5 million, subject to customary post-closing purchase price adjustments. Proceeds from the sale were used to reduce indebtedness under the EXCO Resources Credit Agreement.

Conventional asset divestitures

On July 1, 2016, we closed the sale of our interests in shallow conventional assets located in Pennsylvania and received an overriding royalty interest in each well and approximately $0.1 million, subject to customary post-closing purchase price adjustments. In addition, we retained all rights to other formations below the conventional depths in this region including the Marcellus and Utica shales. For the six months ended June 30, 2016, the divested assets produced approximately 6 Mmcfe per day and the revenues less direct operating expenses, excluding general and administrative costs, generated a net loss of less than $0.1 million. The asset retirement obligations related to the divested wells were $22.6 million on July 1, 2016.

On October 3, 2016, we closed the sale of our interests in shallow conventional assets located in West Virginia for approximately $4.5 million, subject to customary post-closing purchase price adjustments. We retained all rights to other formations below the conventional depths in this region including the Marcellus and Utica shales. For the nine months ended September 30, 2016, the divested assets produced approximately 4 Mmcfe per day and the revenues less direct operating expenses, excluding general and administrative costs, generated net income of $0.7 million. The asset retirement obligations related to the divested wells were $9.7 million on September 30, 2016.

In conjunction with the sales of our shallow conventional assets in Pennsylvania and West Virginia, the Company's field employee count in the Appalachia region has been reduced by 85% since December 31, 2015.

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2016

Asset Retirement Obligation [Abstract]

Asset retirement obligations

Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the nine months endedSeptember 30, 2016:

(in thousands)
Asset retirement obligations at beginning of period	$	41,648
Activity during the period:
Liabilities settled during the period	(59		)
Adjustment to liability due to divestitures (1)	(22,859		)
Accretion of discount	2,006
Asset retirement obligations at end of period	20,736
Less current portion	428
Long-term portion	$	20,308

(1) Adjustment to liability due to divestitures is primarily due to the sale of our conventional assets in Pennsylvania on July 1, 2016. See "Note 3. Divestitures" for additional information.

Our asset retirement obligations are determined using discounted cash flow methodologies based on inputs and assumptions developed by management. We do not have any assets that are legally restricted for purposes of settling asset retirement obligations.

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Oil and Natural Gas Properties

9 Months Ended

Sep. 30, 2016

Oil and Gas Property [Abstract]

Oil and natural gas properties

Oil and natural gas properties

We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. The majority of our undeveloped properties are held-by-production, which reduces the risk of impairment as a result of lease expirations. There were no impairments of unproved properties during the nine months endedSeptember 30, 2016 and we impaired $84.9 million of unproved properties during the nine months ended September 31, 2015.

At the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs ("ceiling test"). The ceiling test involves comparing the net book value of the full cost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record an impairment of our oil and natural gas properties. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our proved reserves by applying the average price as prescribed by the SEC, less estimated future expenditures (based on current costs) to develop and produce the proved reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects.

The ceiling test for each period presented was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing twelve-month simple average spot prices at the first of the month for natural gas at Henry Hub ("HH") and West Texas Intermediate ("WTI") crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in oil and natural gas prices between each of the periods and have a significant impact on our ceiling test limitation.

	Average spot prices
	Oil (per Bbl)		Natural gas (per Mmbtu)
September 30, 2016	$	41.68	$	2.24
June 30, 2016	43.12		2.24
March 31, 2016	46.26		2.40
December 31, 2015	50.28		2.59

We did not recognize an impairment to our proved oil and natural gas properties for the three months ended September 30, 2016, and we recognized impairments to our proved oil and natural gas properties of $160.8 million for the nine months ended September 30, 2016. We recognized impairments to our proved oil and natural gas properties of $339.4 million and $1.0 billionfor the three and nine months endedSeptember 30, 2015, respectively. The impairments were primarily due to the decline in oil and natural gas prices.  Furthermore, the fixed costs associated with certain gathering and transportation contracts continue to have a significant impact on the present value of our proved reserves. Oil and natural gas prices are volatile and we may incur additional impairments during 2016 if future oil and natural gas prices result in a decrease in the trailing twelve-month reference prices compared to September 30, 2016. The possibility and amount of any future impairments is difficult to predict, and will depend, in part, upon future oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves, future capital expenditures and operating costs.

During 2016, all of our proved undeveloped reserves, other than the proved undeveloped reserves associated with certain wells drilled and/or completed in 2016, were reclassified to unproved primarily due to the uncertainty regarding the financing required to develop these reserves.  A significant amount of our proved undeveloped reserves that were reclassified to unproved remain economic at current prices, and we may report proved undeveloped reserves in future filings if we determine we have the financial capability to execute a development plan.  

The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are inherent uncertainties in estimating quantities of proved reserves including projecting the future rates of production and the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data, and engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.

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Earnings Per Share

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Earnings per share

Earnings (loss) per share

The following table presents the basic and diluted earnings (loss) per share computations for the three and nine months endedSeptember 30, 2016 and 2015: 

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands, except per share data)	2016		2015			2016			2015
Basic net income (loss) per common share:
Net income (loss)	$	50,936	$	(354,519	)	$	(190,559	)	$	(1,126,786	)
Weighted average common shares outstanding	279,873		273,348			279,008			272,147
Net income (loss) per basic common share	$	0.18	$	(1.30	)	$	(0.68	)	$	(4.14	)
Diluted net income (loss) per common share:
Net income (loss)	$	50,936	$	(354,519	)	$	(190,559	)	$	(1,126,786	)
Weighted average common shares outstanding	279,873		273,348			279,008			272,147
Dilutive effect of:
Stock options	—		—			—			—
Restricted shares and restricted share units	1,172		—			—			—
Warrants	—		—			—			—
Weighted average common shares and common share equivalents outstanding	281,045		273,348			279,008			272,147
Net income (loss) per diluted common share	$	0.18	$	(1.30	)	$	(0.68	)	$	(4.14	)

Diluted net income (loss) per common share for the three and nine months endedSeptember 30, 2016 and 2015 is computed in the same manner as basic net income (loss) per share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which include stock options, restricted share units, restricted share awards and warrants, whether exercisable or not. The computation of diluted net income (loss) per share excluded 88,083,055 and 36,157,630 antidilutive share equivalents for the three months endedSeptember 30, 2016 and 2015, respectively, and 89,522,616 and 21,200,285 antidilutive share equivalents for the nine months endedSeptember 30, 2016 and 2015, respectively. Our antidilutive share equivalents for the three and nine months endedSeptember 30, 2016 included 80,000,000 warrants issued to Energy Strategic Advisory Services LLC ("ESAS"). See "Note 12. Related party transactions" for additional information on the warrants issued to ESAS. All of our outstanding warrants and stock options were out-of-the-money and considered antidilutive during the three months ended September 30, 2016.

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Derivative Financial Instruments

9 Months Ended

Sep. 30, 2016

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 instruments consists of non-cash income or expense due to changes in the fair value. 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)	September 30, 2016			December 31, 2015
Derivative financial instruments - Current assets	$	5,952		$	39,499
Derivative financial instruments - Long-term assets	1,455			6,109
Derivative financial instruments - Current liabilities	(10,353		)	(16		)
Derivative financial instruments - Long-term liabilities	(1,189		)	—
Net derivative financial instruments	$	(4,135	)	$	45,592

Effect of Derivative Financial Instruments

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2016		2015		2016			2015
Gain (loss) on derivative financial instruments	$	8,209	$	37,348	$	(11,632	)	$	54,427

Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from, or cash disbursements to, our derivative contract counterparties. Changes in the fair value of our derivative financial instrument contracts, which include both cash settlements and non-cash changes in fair value, are included in earnings with a corresponding increase or decrease in the Condensed Consolidated Balance Sheets fair value amounts.

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.

Swaptions:These contracts give our trading counterparties the right, but not the obligation, to enter into a swap contract for an agreed quantity of oil or natural gas from us at a certain time and fixed price in the future. The counterparty to our swaption contracts can choose to exercise its option in December 2016 to enter into 2017 swap contracts.

Collars: A collar is a combination of options including a sold call and a purchased put. These contracts allow us to participate in the upside of commodity prices to the ceiling of the call option and provide us with downside protection through the put option. If the market price is below the strike price of the purchased put at the time of settlement then the counterparty pays us the excess. If the market price is above the strike price of the sold call at 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 the EXCO Resources Credit Agreement 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. Our credit rating and financial condition may restrict our ability to enter into certain types of derivative financial instruments and limit the maturity of the contracts with counterparties. Our derivative contracts also contain rights that could result in the early termination of our derivative contracts and cash payments to our counterparties due to an event of default under the EXCO Resources Credit Agreement.

The following table presents the volumes and fair value of our oil and natural gas derivative financial instruments as of September 30, 2016:

(dollars in thousands, except prices)	Volume Bbtu/Mbbl	Weighted average strike price per Mmbtu/Bbl		Fair value at September 30, 2016
Natural gas:
Swaps:
Remainder of 2016	14,260	$	2.88	$	(1,610	)
2017	23,700	2.99		(2,440		)
2018	3,650	3.15		819
Swaptions:
2017	7,300	2.76		(2,743		)
Collars:
2017	10,950			(420		)
Sold call		3.28
Purchased put		2.87
Total natural gas				$	(6,394	)
Oil:
Swaps:
Remainder of 2016	276	$	58.61	$	2,542
2017	183	50.00		(283		)
Total oil				$	2,259
Total oil and natural gas derivative financial instruments				$	(4,135	)

At December 31, 2015, we had outstanding swap contracts covering 49,370 Bbtu of natural gas and 915 Mbbls of oil.

At September 30, 2016, the average forward NYMEX WTI oil prices per Bbl for the remainder of 2016 and calendar year 2017 were $48.53 and $51.30, respectively, and the average forward NYMEX HH natural gas prices per Mmbtu for the remainder of 2016 and calendar years 2017 and 2018 were $3.02, $3.09 and $2.91, respectively.

Our derivative financial instruments covered approximately 60% and 69% of production volumes for the three months endedSeptember 30, 2016 and 2015, respectively, and 55% and 66% of production volumes for the nine months endedSeptember 30, 2016 and 2015, respectively.

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Debt

9 Months Ended

Sep. 30, 2016

Long-term Debt, Current and Noncurrent [Abstract]

Debt

Debt

The carrying value of our total debt is summarized as follows:

(in thousands)	September 30, 2016			December 31, 2015
EXCO Resources Credit Agreement	$	214,592		$	67,492
Exchange Term Loan	603,116			641,172
Fairfax Term Loan	300,000			300,000
2018 Notes	131,576			158,015
Unamortized discount on 2018 Notes	(589		)	(932		)
2022 Notes	70,169			222,826
Deferred financing costs, net	(12,796		)	(18,294		)
Total debt	1,306,068			1,370,279
Less amounts due within one year	50,000			50,000
Total debt due after one year	$	1,256,068		$	1,320,279

	September 30, 2016
(in thousands)	Carrying value			Deferred reduction in carrying value			Unamortized discount/deferred financing costs		Principal balance
EXCO Resources Credit Agreement	$	214,592		$	—		$	—	$	214,592
Exchange Term Loan	603,116			(203,116		)	—		400,000
Fairfax Term Loan	300,000			—			—		300,000
2018 Notes	130,987			—			589		131,576
2022 Notes	70,169			—			—		70,169
Deferred financing costs, net	(12,796		)	—			12,796		—
Total debt	$	1,306,068		$	(203,116	)	$	13,385	$	1,116,337

Terms and conditions of our debt obligations are discussed below.

Tender Offer and open market repurchases

On August 24, 2016, we completed a cash tender offer for our outstanding senior unsecured notes ("Tender Offer") that resulted in the repurchase of an aggregate of $101.3 million in principal amount of the 2022 Notes for an aggregate purchase price of $40.0 million. Holders of the 2022 Notes that were accepted for payment in the Tender Offer also received accumulated and unpaid interest. The Tender Offer was funded with the borrowings under the EXCO Resources Credit Agreement.

For the nine months endedSeptember 30, 2016, we repurchased an aggregate of $26.4 million and $152.7 million in principal amount of the 2018 Notes and 2022 Notes, respectively, with an aggregate of $53.3 million in cash through the Tender Offer and open market repurchases. These repurchases resulted in net gains on extinguishment of debt of $57.4 million and $119.4 millionfor the three and nine months endedSeptember 30, 2016, respectively.

EXCO Resources Credit Agreement

As of September 30, 2016, we had $214.6 million of outstanding indebtedness and a borrowing base of $325.0 million under the EXCO Resources Credit Agreement. On September 1, 2016, the lenders under the EXCO Resources Credit Agreement postponed the scheduled redetermination of the borrowing base from September 1, 2016 to November 1, 2016 at our request. We are currently working with the lenders to amend the EXCO Resources Credit Agreement and the redetermination of the borrowing base is still in progress. There is no assurance that we will be able to amend the EXCO Resources Credit Agreement and our lenders have discretion in the timing and amount during the redetermination process. In connection with the postponed redetermination, we may not request borrowings from the lenders under the EXCO Resources Credit Agreement that would result in their aggregate exposure to exceed $300.0 million, including letters of credit, until the effective date of the postponed redetermination. Therefore, the Company's available borrowing capacity was $75.4 million as of September 30, 2016.

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 London Interbank Offered Rate ("LIBOR") plus 225 bps to 325 bps (or alternate base rate ("ABR") plus 125 bps to 225 bps), depending on our borrowing base usage. On September 30, 2016, our interest rate was approximately 3.5%.

As of September 30, 2016, we were in compliance with the financial covenants (defined in the EXCO Resources Credit Agreement), which required that we:

• maintain a Consolidated Current Ratio of at least 1.0 to 1.0 as of the end of any fiscal quarter. The consolidated current assets utilized in this ratio include unused commitments under the EXCO Resources Credit Agreement. As of September 30, 2016, the unused commitments were based on the Company's borrowing base of $325.0 million;

• maintain a ratio of consolidated EBITDAX to consolidated interest expense (“Interest Coverage Ratio”) of at least 1.25 to 1.0 as of the end of any fiscal quarter. The consolidated interest expense utilized in the Interest Coverage Ratio is calculated in accordance with GAAP; therefore, this excludes cash payments under the terms of the Exchange Term Loan (as defined below), whether designated as interest or as principal amount, that reduce the carrying amount and are not recognized as interest expense; and

• not permit a Senior Secured Indebtedness Ratio to be greater than 2.5 to 1.0 as of the end of any fiscal quarter. Senior secured indebtedness utilized in the Senior Secured Indebtedness Ratio excludes the Second Lien Term Loans and any other secured indebtedness subordinated to the EXCO Resources Credit Agreement.

Our liquidity and ability to maintain compliance with debt covenants have been negatively impacted by the prolonged depressed oil and natural gas price environment, levels of indebtedness, and gathering, transportation and certain other commercial contracts. Based on our current estimates and expectations, we do not believe we will be able to comply with all of the covenants under the EXCO Resources Credit Agreement for the twelve-month period following the date of these unaudited Condensed Consolidated Financial Statements. See "Note 1. Organization and basis of presentation" for further discussion on this matter.

Second Lien Term Loans

On October 26, 2015, we closed a 12.5% senior secured second lien term loan with certain affiliates of Fairfax Financial Holdings Limited ("Fairfax") in the aggregate principal amount of $300.0 million ("Fairfax Term Loan"). We also closed a 12.5% senior secured second lien term loan with certain unsecured noteholders in the aggregate principal amount of $291.3 million on October 26, 2015 and $108.7 million on November 4, 2015 (“Exchange Term Loan"). The proceeds from the Exchange Term Loan were used to repurchase a portion of the outstanding 2018 Notes and 2022 Notes in exchange for the holders of such notes agreeing to act as lenders in connection with the Exchange Term Loan. The exchange was accounted for as a troubled debt restructuring pursuant to FASB ASC 470-60, Troubled Debt Restructuring by Debtors. The future undiscounted cash flows from the Exchange Term Loan through its maturity were less than the carrying amounts of the retired 2018 Notes and 2022 Notes. As a result, the carrying amount of the Exchange Term Loan is equal to the total undiscounted future cash payments, including interest and principal.  All cash payments under the terms of the Exchange Term Loan, whether designated as interest or as principal amount, will reduce the carrying amount and no interest expense will be recognized. As such, our reported interest expense will be less than the contractual payments throughout the term of the Exchange Term Loan. 

The Second Lien Term Loans mature on October 26, 2020 with interest payable on the last day in each calendar quarter. The Second Lien Term Loans are guaranteed by substantially all of EXCO’s subsidiaries, with the exception of certain non-guarantor subsidiaries and our jointly held equity investments with BG Group, and are secured by second-priority liens on substantially all of EXCO’s assets securing the indebtedness under the EXCO Resources Credit Agreement. The Second Lien Term Loans rank (i) junior to the debt under the EXCO Resources Credit Agreement and any other priority lien obligations, (ii) pari passu to one another and (iii) effectively senior to all of our existing and future unsecured senior indebtedness, including the 2018 Notes and the 2022 Notes, to the extent of the value of collateral.

The agreements governing the Second Lien Term Loans contain covenants that, subject to certain exceptions, limit our ability and the ability of our restricted subsidiaries to, among other things:

• pay dividends or make other distributions or redeem or repurchase our common shares;

• prepay, redeem or repurchase certain debt;

• enter into agreements restricting the subsidiary guarantors’ ability to pay dividends to us or another subsidiary guarantor, make loans or advances to us or transfer assets to us;

• engage in asset sales or substantially alter the business that the we conduct, unless the proceeds are utilized to prepay the Second Lien Term Loans, reduce priority lien indebtedness, or reinvest in the acquisition or development of oil and gas properties;

• enter into transactions with affiliates;

• consolidate, merge or dispose of assets;

• incur liens; and

• enter into sale/leaseback transactions.

In addition, the term loan agreement governing the Exchange Term Loan prohibits us from incurring, among other things and subject to certain exceptions:

• debt under credit facilities, as defined in the term loan credit agreement governing the Exchange Term Loan, in excess of the greatest of (i) $375.0 million plus an amount equal to six and two-thirds percent of the aggregate principal amount of our outstanding indebtedness under the EXCO Resources Credit Agreement for over-advances to protect collateral, (ii) the borrowing base under the EXCO Resources Credit Agreement and (iii) 30% of modified adjusted consolidated net tangible assets (as defined in the agreement);

• second lien debt in excess of $700.0 million; and

• unsecured debt where on the date of such incurrence or after giving effect to such incurrence, our consolidated coverage ratio (as defined in the agreement) is or would be less than 2.25 to 1.0.

The term loan agreement governing the Fairfax Term Loan prohibits us from incurring, among other things and subject to certain exceptions:

• debt under credit facilities, as defined in the term loan credit agreement governing the Fairfax Term Loan, in excess of $375.0 million plus an amount equal to six and two-thirds percent of the aggregate principal amount of our outstanding indebtedness under the EXCO Resources Credit Agreement for over-advances to protect collateral, provided that such indebtedness may not exceed $500.0 million, unless we obtain consent from the administrative agent;

• second lien debt, other than the Exchange Term Loan, in an amount to be agreed upon with the administrative agent;

• junior lien debt, unless such debt is being used to refinance the 2018 Notes or the 2022 Notes or the terms and conditions of such junior lien debt are approved by the administrative agent; and

• unsecured debt, unless we obtain consent from the administrative agent.

In addition, under the term loan credit agreement governing the Fairfax Term Loan, a change of control constitutes an event of default, which, subject to certain limitations, may allow the Fairfax Term Loan lenders to declare the Fairfax Term Loan to be due and payable, in whole or in part, including accrued but unpaid interest thereon, plus an amount equal to all interest payments that would have accrued through the Fairfax Term Loan maturity date. Under the term loan credit agreement governing the Exchange Term Loan, in the event of a change of control EXCO is required to offer to repurchase the Exchange Term Loan at 101% of the face value of the Exchange Term Loan.

In connection with the Second Lien Term Loans, on October 26, 2015, EXCO entered into an intercreditor agreement governing the relationship between EXCO’s lenders and the holders of any other lien obligations that EXCO may issue in the future and a collateral trust agreement governing the administration and maintenance of the collateral securing the Second Lien Term Loans.

2018 Notes

The 2018 Notes are guaranteed on a senior unsecured basis by a majority of EXCO’s subsidiaries, with the exception of certain non-guarantor subsidiaries and our jointly held equity investments with BG Group. Our equity investments, other than OPCO, have been designated as unrestricted subsidiaries under the indenture governing the 2018 Notes.

In the fourth quarter of 2015, EXCO repurchased an aggregate $551.2 million of the 2018 Notes in exchange for certain holders of the 2018 Notes becoming lenders under the Exchange Term Loan. Additionally, as of September 30, 2016, we had repurchased a total of $67.2 million in principal amount of the 2018 Notes for an aggregate of $18.8 million in a series of open market repurchases. As a result of the repurchases, the aggregate principal amount of outstanding 2018 Notes was reduced to $131.6 million as of September 30, 2016. Interest accrues at 7.5% per annum and is payable semi-annually in arrears on March 15 and September 15 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 stock;

• 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

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. In the fourth quarter of 2015, EXCO repurchased an aggregate $277.2 million in principal amount of the 2022 Notes in exchange for certain holders of the 2022 Notes becoming lenders under the Exchange Term Loan. On August 24, 2016, we completed the Tender Offer that resulted in the repurchases of an aggregate of $101.3 million in principal amount of the 2022 Notes for an aggregate purchase price of $40.0 million. As of September 30, 2016, through the Tender Offer and a series of open market repurchases, we had repurchased a total of $152.7 million in principal amount of the 2022 Notes for an aggregate of $46.5 million. As a result of the repurchases, the aggregate principal amount of outstanding 2022 Notes was reduced to $70.2 million as of September 30, 2016.

In conjunction with the Tender Offer, we solicited consents from the registered holders of the 2022 Notes to amend certain terms of the indenture governing the 2022 Notes. Following the consummation of the consent solicitation, we entered into a supplemental indenture governing the 2022 Notes to amend the definition of “Credit Facilities” to include debt securities as a permitted form of additional secured indebtedness, in addition to the term loans and other credit facilities currently permitted.

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.

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Commitments and contingencies (Notes)

9 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and contingencies

Commitments and contingencies

Settlement of Participation Agreement litigation

In July 2013, we entered into a participation agreement with a joint venture partner for the development of certain assets in the Eagle Ford shale ("Participation Agreement"). As described in "Item 3. Legal Proceedings" in our 2015 Form 10-K, we were in a dispute subject to litigation over the offer and the acceptance process with our joint venture partner.

On July 25, 2016, we settled the litigation with our joint venture partner, and the litigation was thereafter dismissed after a final judgment order was entered in response to the parties’ joint motion to dismiss the case with prejudice. Among other things, the settlement provided a full release for any claims, rights, demands, damages and causes of action that either party has asserted or could have asserted for any breach of the Participation Agreement. As part of the settlement, the parties amended and restated the Participation Agreement to (i) eliminate our requirement to offer to purchase our joint venture partner's interests in certain wells each quarter, (ii) eliminate our requirement to convey a portion of our working interest to our joint venture partner upon commencing development of future locations, (iii) terminate the area of mutual interest, which required either party acquiring an interest in non-producing acreage included in certain areas to provide notice of the acquisition to the non-acquiring party and allowed the non-acquiring party to acquire a proportionate share in such acquired interest, (iv) provide that EXCO transfer to its joint venture partner a portion of its interests in certain producing wells and certain undeveloped locations in South Texas (“Transferred Interests”), effective May 1, 2016 and (v) modify or eliminate certain other provisions.

We recorded a loss in "Other operating items" in the Condensed Consolidated Statements of Operations, and a corresponding credit to the "Proved developed and undeveloped oil and natural gas properties" in our Condensed Consolidated Balance Sheet during the nine months ended September 30, 2016. The fair value of the Transferred Interests was $23.2 million as of July 25, 2016 based on a discounted cash flow model of the estimated reserves using NYMEX forward strip prices. See "Note 10. Fair value measurements" for additional information. The net production from the Transferred Interests was approximately 350 Bbls of oil per day during June 2016.

Natural gas sales and firm transportation contract litigation

During the third quarter of 2016, we terminated our sales and transportation contracts with Enterprise Products Operating LLC (“Enterprise”) and Acadian Gas Pipeline System (“Acadian”), respectively. We transported natural gas produced from our operated wells in North Louisiana through Acadian, and Enterprise was a purchaser of certain volumes of our natural gas, until we terminated the contracts. Enterprise and Acadian are part of the corporate family of Enterprise Products Partners L.P. (“EPD”). Acadian is an indirect, wholly-owned subsidiary of EPD that owns and operates the Acadian natural gas pipeline system. The agreement with Acadian provided for the firm transportation of 150,000 Mmbtu/day and 175,000 Mmbtu/day of natural gas at reservation fees of $0.25 and $0.20, respectively. In addition, the sales contract with Enterprise contemplated that we could, subject to certain limitations and exclusions, sell 75,000 Mmbtu/day of natural gas at a $0.25 reduction from market index prices. The primary term for these contracts had been through October 31, 2025. The fees described represent our gross commitments and a portion of these costs is allocated to working interest and other owners. The Acadian firm transportation agreement is accounted for as gathering and transportation expenses and the Enterprise sales contract is accounted for as a reduction in the total sales price within revenues.

Under the parties’ sales and transportation agreements, Enterprise owed us for July 2016 natural gas sales, and we owed Acadian for July 2016 transportation fees. The amount owed to us by Enterprise exceeded the amount owed by us to Acadian. We notified Enterprise in writing of its failure to pay and gave Enterprise opportunity to cure. When Enterprise failed to cure, we gave written notice to Enterprise and Acadian that we were terminating the sales and transportation agreements. Enterprise and Acadian subsequently filed an action in Harris County, Texas, against us alleging that we could not terminate the parties’ agreements despite Enterprise's uncured payment default under the natural gas sales agreement, and further alleged that we were in breach of the firm transportation agreements. On October 17, 2016, we filed a counterclaim asserting that Enterprise was the breaching party because it improperly withheld payment for natural gas we delivered to it and the amounts owed by Enterprise exceeded the amounts owed by us to Acadian. We are also seeking a declaration that we properly terminated the contracts with Enterprise and Acadian. We cannot currently estimate or predict the outcome of the litigation but we plan to vigorously defend our right to terminate the contracts and to seek the amounts owed to us for delivered natural gas.

We are no longer selling natural gas under the Enterprise sales contract or transporting natural gas under the Acadian firm transportation contract effective as of the termination date. The Company is accounting for these contracts in accordance with FASB ASC 450 ("ASC 450"), Contingencies, which states a contingency that might result in a gain should not be reflected until it is realized or realizable. There is a rebuttable presumption that a claim subject to litigation does not meet the criteria to be realized or realizable; therefore, the termination of these contracts will not be reflected in our financial results until the litigation is resolved. Upon resolution of the litigation, we will adjust the previously recognized amounts to reflect the outcome of the litigation. As of September 30, 2016, we recorded a $6.4 million receivable related to the net amounts owed by Enterprise prior to the termination of the contracts and an accrual of $2.1 million for costs subsequent to the termination of the contract in accordance with the guidance related to contingencies in ASC 450.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2016

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 ratings, futures markets and forward curves, and readily available buyers or sellers. During the nine months endedSeptember 30, 2016 and 2015 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 September 30, 2016 and December 31, 2015.

	September 30, 2016
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	(4,135	)	$	—	$	(4,135	)
	December 31, 2015
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	45,592		$	—	$	45,592

We evaluate derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them on a gross basis in our Condensed Consolidated Balance Sheets. Net 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 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, collars and swaption contracts, is discussed below.

Oil derivatives. Our oil derivatives are swap contracts for notional barrels of oil at fixed 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, and (iii) the applicable credit-adjusted risk-free rate curve, as described above.

Natural gas derivatives. Our natural gas derivatives are swap, collar and swaption contracts for notional Mmbtus of natural gas at posted price indexes, including NYMEX HH swap, option and swaption 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 natural gas swaps, (iii) the applicable credit-adjusted risk-free rate curve, as described above, and (iv) the implied rates of volatility inherent in the option and swaption contracts. The implied rates of volatility were determined based on the average of historical HH natural gas prices.

See further details on the fair value of our derivative financial instruments in “Note 7. Derivative financial instruments”.

Fair value of other financial instruments

Our financial instruments include cash and cash equivalents, accounts receivable and payable and accrued liabilities.  The carrying amount of these instruments approximates fair value because of their short-term nature.

The carrying values of our borrowings under the EXCO Resources Credit Agreement approximate fair value, as these are subject to short-term floating interest rates that approximate the rates available to us for those periods.

The estimated fair values of our 2018 Notes, 2022 Notes, Exchange Term Loan and Fairfax Term Loan are presented below. The estimated fair values of the 2018 Notes and 2022 Notes have been calculated based on quoted prices in active markets. The estimated fair values of the Exchange Term Loan and the Fairfax Term Loan have been calculated based on quoted prices obtained from third-party pricing sources and are classified as Level 2.

	September 30, 2016
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	60,438	$	—	$	—	$	60,438
2022 Notes	27,366		—		—		27,366
Exchange Term Loan	—		263,500		—		263,500
Fairfax Term Loan	—		197,625		—		197,625
	December 31, 2015
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	43,170	$	—	$	—	$	43,170
2022 Notes	48,376		—		—		48,376
Exchange Term Loan	—		278,000		—		278,000
Fairfax Term Loan	—		208,500		—		208,500

Other fair value measurements

During the nine months endedSeptember 30, 2016, we impaired $4.9 million of our investment in a midstream company in the East Texas and North Louisiana regions that we account for under the cost method of accounting. The impairment was recorded to reduce the carrying value to the fair value and is considered to be Level 3 within the fair value hierarchy. The estimated fair value of our cost method investment was determined based on trading metrics of comparable transactions.

As discussed in "Note 9. Commitments and contingencies", we recorded a $23.2 million loss in "Other operating items" in our Condensed Consolidated Statements of Operations for the nine months ended September 30, 2016 and a corresponding credit to our "Proved developed and undeveloped oil and natural gas properties" in our balance sheet related to the settlement of litigation with a joint venture partner in the Eagle Ford shale. The fair market value of the properties transferred pursuant to the settlement was determined using 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. The fair value measurements utilized included significant unobservable inputs that are considered to be Level 3 within the fair value hierarchy. These unobservable inputs include management's estimates of reserve quantities, commodity prices, operating costs, development costs, discount factors and other risk factors applied to the future cash flows.

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Income Taxes

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Income taxes

Income taxes

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. We have accumulated financial deferred tax assets primarily due to losses arising from impairments to the carrying value of our oil and natural gas properties that are subject to valuation allowances. Our valuation allowances increased $69.4 million for the nine months endedSeptember 30, 2016. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $1.4 billion that have fully offset our net deferred tax assets as of September 30, 2016. The valuation allowances will continue to be recognized until the realization of future deferred tax benefits are more likely than not to become utilized. The valuation allowances do not impact future utilization of the underlying tax attributes.

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Related Party Transactions

9 Months Ended

Sep. 30, 2016

Related Party Transactions [Abstract]

Related party transactions

Related party transactions

OPCO

OPCO serves as the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis. We did not advance any funds to OPCO during three and nine months endedSeptember 30, 2016 or 2015. 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 three and nine months endedSeptember 30, 2016 and 2015, these transactions included the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2016		2015		2016		2015
Amounts received from OPCO	$	3,824	$	7,281	$	12,586	$	23,847

As of September 30, 2016 and December 31, 2015, the amounts owed were as follows:

(in thousands)	September 30, 2016		December 31, 2015
Amounts due to EXCO (1)	$	932	$	1,733
Amounts due from EXCO (1)	12,903		10,410

(1) Advances to OPCO are recorded in "Other current assets" in our Condensed Consolidated Balance Sheets. Any amounts we owe to OPCO are netted against the advance until the advances are utilized. If the advances are fully utilized, we record amounts owed in "Accounts payable and accrued liabilities" in our Condensed Consolidated Balance Sheets.

ESAS

On September 8, 2015, we closed the services and investment agreement with ESAS, a wholly owned subsidiary of Bluescape Resources Company LLC ("Bluescape"). At the closing, C. John Wilder, Executive Chairman of Bluescape, was appointed as a member of our Board of Directors and as Executive Chairman of the Board of Directors. As part of the agreement, ESAS completed its required purchase of EXCO's common shares as of December 31, 2015 and is currently the beneficial owner of approximately 6.5% of our outstanding common shares.

As consideration for the services provided under the agreement, EXCO pays ESAS a monthly fee of $300,000 and an annual incentive payment of up to $2.4 million per year that is based on EXCO’s common share price achieving certain performance hurdles as compared to a peer group. The monthly fees were held in escrow until one year following the closing of the agreement and reported as "Restricted cash" on our Condensed Consolidated Balance Sheets. In September 2016, we made a cash payment to ESAS of $7.2 million, which consisted of (i) the monthly fees previously held in escrow and (ii) a $2.4 million annual incentive payment as a result of EXCO achieving a performance rank above the 75th percentile of the peer group. Our accrual totaled $0.9 million and $4.5 million at September 30, 2016 and December 31, 2015, respectively, for the services performed under the services and investment agreement, and is recorded in "Accounts payable and accrued liabilities" in our Condensed Consolidated Balance Sheets. The amount at September 30, 2016 includes an accrual for the annual incentive payment of $0.6 million as a result of EXCO's performance rank.

As an additional performance incentive under the services and investment agreement, EXCO issued warrants to ESAS in four tranches to purchase an aggregate of 80,000,000 common shares. These warrants may become exercisable in the future if our common shares achieve certain performance metrics compared to a peer group as of March 31, 2019. The measurement of the warrants is accounted for in accordance with ASC Topic 505-50, Equity-Based Payments to Non-Employees, which requires the warrants to be re-measured each interim reporting period until the completion of the services on March 31, 2019 and an adjustment is recorded in the statement of operations within equity-based compensation expense. For the three and nine months endedSeptember 30, 2016, we recognized equity-based compensation related to the warrants of $0.9 million and $11.8 million, respectively, and $0.2 million for the three and nine months ended September 30, 2015.

In the first quarter of 2016, ESAS entered into an agreement with an unaffiliated lender under the Exchange Term Loan, pursuant to which the lender will make periodic payments to ESAS or receive periodic payments from ESAS based on changes in the market value of the Exchange Term Loan, and the lender will make periodic payments to ESAS based on the interest rate of the Exchange Term Loan. As of September 30, 2016, the agreement effectively provided ESAS with the economic consequences of ownership of approximately $47.9 million in principal amount of the Exchange Term Loan without direct ownership of, or consent rights with respect to, the Exchange Term Loan.

As described above, ESAS is a wholly owned subsidiary of Bluescape, and C. John Wilder, a member of our Board of Directors, is Bluescape’s Executive Chairman. As Bluescape’s Executive Chairman, Mr. Wilder has the power to direct the affairs of Bluescape and, indirectly, ESAS, and may be deemed to share ESAS’s interest in the Exchange Term Loan and our common shares.

See our 2015 Form 10-K for additional disclosures related to the services and investment agreement and the related warrants.

Fairfax

Hamblin Watsa Investment Counsel Ltd. (“Hamblin Watsa”), a wholly owned subsidiary of Fairfax, is the administrative agent of the Fairfax Term Loan and certain affiliates of Fairfax are lenders under the Fairfax Term Loan and a portion of the Exchange Term Loan. As of September 30, 2016, affiliates of Fairfax were the record holders of approximately $112.1 million in principal amount of the Exchange Term Loan. Samuel A. Mitchell, a member of our Board of Directors, is a Managing Director of Hamblin Watsa and a member of Hamblin Watsa’s investment committee, which consists of seven members that manage the investment portfolio of Fairfax. Based on filings with the SEC, Fairfax is the beneficial owner of approximately 9.0% of our outstanding common shares. See “Note 8. Debt” for additional information.

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Condensed Consolidating Financial Statements

9 Months Ended

Sep. 30, 2016

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Condensed consolidating financial statements

Condensed consolidating financial statements

As of September 30, 2016, the majority of EXCO’s subsidiaries were guarantors under the EXCO Resources Credit Agreement and the indentures governing the 2018 Notes and 2022 Notes and the agreements governing the Second Lien Term Loans. All of our unrestricted subsidiaries under the Second Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes are considered non-guarantor subsidiaries.

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The 2018 Notes, 2022 Notes and the Second Lien Term Loans, which were issued by EXCO Resources, Inc., are jointly and severally guaranteed by substantially all of our subsidiaries (referred to as Guarantor Subsidiaries). For purposes of this footnote, EXCO Resources, Inc. is referred to as Resources to distinguish it from the Guarantor Subsidiaries. Each of the Guarantor Subsidiaries is a 100% owned subsidiary of Resources and the guarantees are unconditional as they relate to the assets of the Guarantor Subsidiaries.

The following financial information presents consolidating financial statements, which include:

• Resources;

• the Guarantor Subsidiaries;

• the Non-Guarantor Subsidiaries;

• elimination entries necessary to consolidate Resources, the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries; and

• EXCO on a consolidated basis.

Investments in subsidiaries are accounted for using the equity method of accounting for the disclosures within this footnote. The financial information for the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries is presented on a combined basis. The elimination entries primarily eliminate investments in subsidiaries and intercompany balances and transactions.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

September 30, 2016

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	9,754		$	(6,220	)	$	—	$	—		$	3,534
Restricted cash	—			18,434			—		—			18,434
Other current assets	13,233			75,608			—		—			88,841
Total current assets	22,987			87,822			—		—			110,809
Equity investments	—			—			31,973		—			31,973
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	—			93,511			—		—			93,511
Proved developed and undeveloped oil and natural gas properties	331,326			2,615,315			—		—			2,946,641
Accumulated depletion	(330,776		)	(2,359,835		)	—		—			(2,690,611		)
Oil and natural gas properties, net	550			348,991			—		—			349,541
Other property and equipment, net	608			23,450			—		—			24,058
Investments in and advances to affiliates, net	452,896			—			—		(452,896		)	—
Deferred financing costs, net	5,000			—			—		—			5,000
Derivative financial instruments	1,455			—			—		—			1,455
Goodwill	13,293			149,862			—		—			163,155
Total assets	$	496,789		$	610,125		$	31,973	$	(452,896	)	$	685,991
Liabilities and shareholders' equity
Current liabilities	$	74,818		$	167,105		$	—	$	—		$	241,923
Long-term debt	1,256,068			—			—		—			1,256,068
Other long-term liabilities	3,493			22,097			—		—			25,590
Payable to parent	—			2,360,227			—		(2,360,227		)	—
Total shareholders' equity	(837,590		)	(1,939,304		)	31,973		1,907,331			(837,590		)
Total liabilities and shareholders' equity	$	496,789		$	610,125		$	31,973	$	(452,896	)	$	685,991

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2015

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	34,296		$	(22,049	)	$	—	$	—		$	12,247
Restricted cash	2,100			19,120			—		—			21,220
Other current assets	51,133			65,201			—		—			116,334
Total current assets	87,529			62,272			—		—			149,801
Equity investments	—			—			40,797		—			40,797
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	—			115,377			—		—			115,377
Proved developed and undeveloped oil and natural gas properties	330,775			2,739,655			—		—			3,070,430
Accumulated depletion	(330,775		)	(2,296,988		)	—		—			(2,627,763		)
Oil and natural gas properties, net	—			558,044			—		—			558,044
Other property and equipment, net	749			27,063			—		—			27,812
Investments in and advances to affiliates, net	616,940			—			—		(616,940		)	—
Deferred financing costs, net	8,408			—			—		—			8,408
Derivative financial instruments	6,109			—			—		—			6,109
Goodwill	13,293			149,862			—		—			163,155
Total assets	$	733,028		$	797,241		$	40,797	$	(616,940	)	$	954,126
Liabilities and shareholders' equity
Current liabilities	$	74,472		$	178,447		$	—	$	—		$	252,919
Long-term debt	1,320,279			—			—		—			1,320,279
Other long-term liabilities	600			42,651			—		—			43,251
Payable to parent	—			2,276,594			—		(2,276,594		)	—
Total shareholders' equity	(662,323		)	(1,700,451		)	40,797		1,659,654			(662,323		)
Total liabilities and shareholders' equity	$	733,028		$	797,241		$	40,797	$	(616,940	)	$	954,126

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months endedSeptember 30, 2016

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	70,862		$	—		$	—	$	70,862
Purchased natural gas and marketing	—			6,324			—			—		6,324
Total revenues	—			77,186			—			—		77,186
Costs and expenses:
Oil and natural gas production	—			12,608			—			—		12,608
Gathering and transportation	—			27,979			—			—		27,979
Purchased natural gas	—			6,586			—			—		6,586
Depletion, depreciation and amortization	89			15,821			—			—		15,910
Impairment of oil and natural gas properties	—			—			—			—		—
Accretion of discount on asset retirement obligations	—			325			—			—		325
General and administrative	(4,395		)	15,141			—			—		10,746
Other operating items	—			(1,110		)	—			—		(1,110		)
Total costs and expenses	(4,306		)	77,350			—			—		73,044
Operating income (loss)	4,306			(164		)	—			—		4,142
Other income (expense):
Interest expense, net	(16,997		)	—			—					(16,997		)
Gain on derivative financial instruments	8,209			—			—					8,209
Gain on extinguishment of debt	57,421			—			—					57,421
Other income	4			8			—					12
Equity loss	—			—			(823		)			(823		)
Net loss from consolidated subsidiaries	(979		)	—			—			979		—
Total other income (expense)	47,658			8			(823		)	979		47,822
Income (loss) before income taxes	51,964			(156		)	(823		)	979		51,964
Income tax expense	1,028			—			—			—		1,028
Net income (loss)	$	50,936		$	(156	)	$	(823	)	$	979	$	50,936

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months endedSeptember 30, 2015

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	83,744		$	—		$	—	$	83,744
Purchased natural gas and marketing	—			6,773			—			—		6,773
Total revenues	—			90,517			—			—		90,517
Costs and expenses:
Oil and natural gas production	7			18,606			—			—		18,613
Gathering and transportation	—			23,743			—			—		23,743
Purchased natural gas	—			6,991			—			—		6,991
Depletion, depreciation and amortization	229			51,784			—			—		52,013
Impairment of oil and natural gas properties	1,372			338,021			—			—		339,393
Accretion of discount on asset retirement obligations	—			574			—			—		574
General and administrative	(2,345		)	15,738			—			—		13,393
Other operating items	(3		)	(225		)	—			—		(228		)
Total costs and expenses	(740		)	455,232			—			—		454,492
Operating income (loss)	740			(364,715		)	—			—		(363,975		)
Other income (expense):
Interest expense, net	(27,761		)	—			—			—		(27,761		)
Gain on derivative financial instruments	37,348			—			—			—		37,348
Other income	14			7			—			—		21
Equity loss	—			—			(152		)	—		(152		)
Net loss from consolidated subsidiaries	(364,860		)	—			—			364,860		—
Total other income (expense)	(355,259		)	7			(152		)	364,860		9,456
Loss before income taxes	(354,519		)	(364,708		)	(152		)	364,860		(354,519		)
Income tax expense	—			—			—			—		—
Net loss	$	(354,519	)	$	(364,708	)	$	(152	)	$	364,860	$	(354,519	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months endedSeptember 30, 2016

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	176,732		$	—		$	—	$	176,732
Purchased natural gas and marketing	—			15,335			—			—		15,335
Total revenues	—			192,067			—			—		192,067
Costs and expenses:
Oil and natural gas production	4			39,139			—			—		39,143
Gathering and transportation	—			79,828			—			—		79,828
Purchased natural gas	—			17,273			—			—		17,273
Depletion, depreciation and amortization	298			63,697			—			—		63,995
Impairment of oil and natural gas properties	838			159,975			—			—		160,813
Accretion of discount on asset retirement obligations	—			2,006			—			—		2,006
General and administrative	(6,062		)	44,688			—			—		38,626
Other operating items	(406		)	24,342			—			—		23,936
Total costs and expenses	(5,328		)	430,948			—			—		425,620
Operating income (loss)	5,328			(238,881		)	—			—		(233,553		)
Other income (expense):
Interest expense, net	(54,186		)	—			—			—		(54,186		)
Loss on derivative financial instruments	(11,632		)	—			—			—		(11,632		)
Gain on extinguishment of debt	119,374			—			—			—		119,374
Other income	9			28			—			—		37
Equity loss	—			—			(8,824		)	—		(8,824		)
Net loss from consolidated subsidiaries	(247,677		)	—			—			247,677		—
Total other income (expense)	(194,112		)	28			(8,824		)	247,677		44,769
Loss before income taxes	(188,784		)	(238,853		)	(8,824		)	247,677		(188,784		)
Income tax expense	1,775			—			—			—		1,775
Net loss	$	(190,559	)	$	(238,853	)	$	(8,824	)	$	247,677	$	(190,559	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months endedSeptember 30, 2015

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	4		$	264,143		$	—		$	—	$	264,147
Purchased natural gas and marketing	—			21,012			—			—		21,012
Total revenues	4			285,155			—			—		285,159
Costs and expenses:
Oil and natural gas production	30			58,123			—			—		58,153
Gathering and transportation	—			74,243			—			—		74,243
Purchased natural gas	—			21,571			—			—		21,571
Depletion, depreciation and amortization	753			175,407			—			—		176,160
Impairment of oil and natural gas properties	8,263			1,001,784			—			—		1,010,047
Accretion of discount on asset retirement obligations	4			1,694			—			—		1,698
General and administrative	(6,569		)	47,796			—			—		41,227
Other operating items	2,065			(947		)	—			—		1,118
Total costs and expenses	4,546			1,379,671			—			—		1,384,217
Operating loss	(4,542		)	(1,094,516		)	—			—		(1,099,058		)
Other income (expense):
Interest expense, net	(80,822		)	—			—			—		(80,822		)
Gain on derivative financial instruments	54,427			—			—			—		54,427
Other income	87			32			—			—		119
Equity loss	—			—			(1,452		)	—		(1,452		)
Net loss from consolidated subsidiaries	(1,095,936		)	—			—			1,095,936		—
Total other income (expense)	(1,122,244		)	32			(1,452		)	1,095,936		(27,728		)
Loss before income taxes	(1,126,786		)	(1,094,484		)	(1,452		)	1,095,936		(1,126,786		)
Income tax expense	—			—			—			—		—
Net loss	$	(1,126,786	)	$	(1,094,484	)	$	(1,452	)	$	1,095,936	$	(1,126,786	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months endedSeptember 30, 2016

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	9,152		$	(12,892	)	$	—	$	—	$	(3,740	)
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(1,250		)	(69,205		)	—		—		(70,455		)
Proceeds from disposition of property and equipment	10			11,232			—		—		11,242
Restricted cash	—			686			—		—		686
Net changes in advances to joint ventures	—			2,377			—		—		2,377
Equity investments and other	—			—			—		—		—
Advances/investments with affiliates	(83,631		)	83,631			—		—		—
Net cash provided by (used in) investing activities	(84,871		)	28,721			—		—		(56,150		)
Financing Activities:
Borrowings under EXCO Resources Credit Agreement	390,897			—			—		—		390,897
Repayments under EXCO Resources Credit Agreement	(243,797		)	—			—		—		(243,797		)
Payments on Exchange Term Loan	(38,056		)	—			—		—		(38,056		)
Repurchases of senior unsecured notes	(53,298		)	—			—		—		(53,298		)
Deferred financing costs and other	(4,569		)	—			—		—		(4,569		)
Net cash provided by financing activities	51,177			—			—		—		51,177
Net increase (decrease) in cash	(24,542		)	15,829			—		—		(8,713		)
Cash at beginning of period	34,296			(22,049		)	—		—		12,247
Cash at end of period	$	9,754		$	(6,220	)	$	—	$	—	$	3,534

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months endedSeptember 30, 2015

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	27,860		$	98,996		$	—	$	—	$	126,856
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(1,784		)	(275,532		)	—		—		(277,316		)
Proceeds from disposition of property and equipment	686			6,711			—		—		7,397
Restricted cash	—			4,016			—		—		4,016
Net changes in advances to joint ventures	—			8,594			—		—		8,594
Equity investments and other	—			1,455			—		—		1,455
Advances/investments with affiliates	(181,813		)	181,813			—		—		—
Net cash used in investing activities	(182,911		)	(72,943		)	—		—		(255,854		)
Financing Activities:
Borrowings under EXCO Resources Credit Agreement	97,500			—			—		—		97,500
Proceeds from issuance of common shares, net	9,829			—			—		—		9,829
Deferred financing costs and other	(4,125		)	—			—		—		(4,125		)
Net cash provided by financing activities	103,204			—			—		—		103,204
Net increase (decrease) in cash	(51,847		)	26,053			—		—		(25,794		)
Cash at beginning of period	86,837			(40,532		)	—		—		46,305
Cash at end of period	$	34,990		$	(14,479	)	$	—	$	—	$	20,511

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Summary Of Significant Accounting Policies (Policy)

9 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Industry Specific Policies, Oil and Gas

Oil and natural gas properties

We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. The majority of our undeveloped properties are held-by-production, which reduces the risk of impairment as a result of lease expirations. There were no impairments of unproved properties during the nine months endedSeptember 30, 2016 and we impaired $84.9 million of unproved properties during the nine months ended September 31, 2015.

At the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs ("ceiling test"). The ceiling test involves comparing the net book value of the full cost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record an impairment of our oil and natural gas properties. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our proved reserves by applying the average price as prescribed by the SEC, less estimated future expenditures (based on current costs) to develop and produce the proved reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects.

The ceiling test for each period presented was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing twelve-month simple average spot prices at the first of the month for natural gas at Henry Hub ("HH") and West Texas Intermediate ("WTI") crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in oil and natural gas prices between each of the periods and have a significant impact on our ceiling test limitation.

	Average spot prices
	Oil (per Bbl)		Natural gas (per Mmbtu)
September 30, 2016	$	41.68	$	2.24
June 30, 2016	43.12		2.24
March 31, 2016	46.26		2.40
December 31, 2015	50.28		2.59

We did not recognize an impairment to our proved oil and natural gas properties for the three months ended September 30, 2016, and we recognized impairments to our proved oil and natural gas properties of $160.8 million for the nine months ended September 30, 2016. We recognized impairments to our proved oil and natural gas properties of $339.4 million and $1.0 billionfor the three and nine months endedSeptember 30, 2015, respectively. The impairments were primarily due to the decline in oil and natural gas prices.  Furthermore, the fixed costs associated with certain gathering and transportation contracts continue to have a significant impact on the present value of our proved reserves. Oil and natural gas prices are volatile and we may incur additional impairments during 2016 if future oil and natural gas prices result in a decrease in the trailing twelve-month reference prices compared to September 30, 2016. The possibility and amount of any future impairments is difficult to predict, and will depend, in part, upon future oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves, future capital expenditures and operating costs.

During 2016, all of our proved undeveloped reserves, other than the proved undeveloped reserves associated with certain wells drilled and/or completed in 2016, were reclassified to unproved primarily due to the uncertainty regarding the financing required to develop these reserves.  A significant amount of our proved undeveloped reserves that were reclassified to unproved remain economic at current prices, and we may report proved undeveloped reserves in future filings if we determine we have the financial capability to execute a development plan.  

The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are inherent uncertainties in estimating quantities of proved reserves including projecting the future rates of production and the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data, and engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.

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Organization And Basis Of Presentation Organization and Basis of Presentation (Tables)

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Change in Accounting Estimate [Table Text Block]

The following table reflects the revisions to prior periods:

					Three months ended
(in thousands)					June 30, 2016			March 31, 2016
Gathering and transportation, previously reported					$	26,895		$	26,630
Revision of third party natural gas purchases and sales					(151		)	(1,525		)
Gathering and transportation, as currently reported					$	26,744		$	25,105
Purchased natural gas and marketing revenues					$	4,570		$	4,441
Purchased natural gas expenses					$	4,721		$	5,966
	Three months ended
(in thousands)	December 31, 2015		September 31, 2015		June 30, 2015			March 31, 2015
Natural gas revenues, previously reported	$	41,828	$	56,082	$	62,197		$	65,437
Revision of third party natural gas purchases and sales	368		218		184			157
Natural gas revenues, as currently reported	$	42,196	$	56,300	$	62,381		$	65,594
Purchased natural gas and marketing revenues	$	5,430	$	6,773	$	6,678		$	7,561
Purchased natural gas expenses	$	5,798	$	6,991	$	6,862		$	7,718

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2016

Asset Retirement Obligation [Abstract]

Schedule of Asset Retirement Obligations

The following is a reconciliation of our asset retirement obligations for the nine months endedSeptember 30, 2016:

(in thousands)
Asset retirement obligations at beginning of period	$	41,648
Activity during the period:
Liabilities settled during the period	(59		)
Adjustment to liability due to divestitures (1)	(22,859		)
Accretion of discount	2,006
Asset retirement obligations at end of period	20,736
Less current portion	428
Long-term portion	$	20,308

(1) Adjustment to liability due to divestitures is primarily due to the sale of our conventional assets in Pennsylvania on July 1, 2016. See "Note 3. Divestitures" for additional information.

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Oil and Natural Gas Properties Oil and Natural Gas Properties (Tables)

9 Months Ended

Sep. 30, 2016

Oil and Gas Property [Abstract]

Average spot price

	Average spot prices
	Oil (per Bbl)		Natural gas (per Mmbtu)
September 30, 2016	$	41.68	$	2.24
June 30, 2016	43.12		2.24
March 31, 2016	46.26		2.40
December 31, 2015	50.28		2.59

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2016

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 three and nine months endedSeptember 30, 2016 and 2015: 

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands, except per share data)	2016		2015			2016			2015
Basic net income (loss) per common share:
Net income (loss)	$	50,936	$	(354,519	)	$	(190,559	)	$	(1,126,786	)
Weighted average common shares outstanding	279,873		273,348			279,008			272,147
Net income (loss) per basic common share	$	0.18	$	(1.30	)	$	(0.68	)	$	(4.14	)
Diluted net income (loss) per common share:
Net income (loss)	$	50,936	$	(354,519	)	$	(190,559	)	$	(1,126,786	)
Weighted average common shares outstanding	279,873		273,348			279,008			272,147
Dilutive effect of:
Stock options	—		—			—			—
Restricted shares and restricted share units	1,172		—			—			—
Warrants	—		—			—			—
Weighted average common shares and common share equivalents outstanding	281,045		273,348			279,008			272,147
Net income (loss) per diluted common share	$	0.18	$	(1.30	)	$	(0.68	)	$	(4.14	)

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Derivative Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2016

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Fair Value Of Derivative Financial Instruments

Fair Value of Derivative Financial Instruments

(in thousands)	September 30, 2016			December 31, 2015
Derivative financial instruments - Current assets	$	5,952		$	39,499
Derivative financial instruments - Long-term assets	1,455			6,109
Derivative financial instruments - Current liabilities	(10,353		)	(16		)
Derivative financial instruments - Long-term liabilities	(1,189		)	—
Net derivative financial instruments	$	(4,135	)	$	45,592

Effect Of Derivative Financial Instruments

Effect of Derivative Financial Instruments

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2016		2015		2016			2015
Gain (loss) on derivative financial instruments	$	8,209	$	37,348	$	(11,632	)	$	54,427

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 September 30, 2016:

(dollars in thousands, except prices)	Volume Bbtu/Mbbl	Weighted average strike price per Mmbtu/Bbl		Fair value at September 30, 2016
Natural gas:
Swaps:
Remainder of 2016	14,260	$	2.88	$	(1,610	)
2017	23,700	2.99		(2,440		)
2018	3,650	3.15		819
Swaptions:
2017	7,300	2.76		(2,743		)
Collars:
2017	10,950			(420		)
Sold call		3.28
Purchased put		2.87
Total natural gas				$	(6,394	)
Oil:
Swaps:
Remainder of 2016	276	$	58.61	$	2,542
2017	183	50.00		(283		)
Total oil				$	2,259
Total oil and natural gas derivative financial instruments				$	(4,135	)

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Debt (Tables)

9 Months Ended

Sep. 30, 2016

Long-term Debt, Current and Noncurrent [Abstract]

Schedule Of Debt

The carrying value of our total debt is summarized as follows:

(in thousands)	September 30, 2016			December 31, 2015
EXCO Resources Credit Agreement	$	214,592		$	67,492
Exchange Term Loan	603,116			641,172
Fairfax Term Loan	300,000			300,000
2018 Notes	131,576			158,015
Unamortized discount on 2018 Notes	(589		)	(932		)
2022 Notes	70,169			222,826
Deferred financing costs, net	(12,796		)	(18,294		)
Total debt	1,306,068			1,370,279
Less amounts due within one year	50,000			50,000
Total debt due after one year	$	1,256,068		$	1,320,279

	September 30, 2016
(in thousands)	Carrying value			Deferred reduction in carrying value			Unamortized discount/deferred financing costs		Principal balance
EXCO Resources Credit Agreement	$	214,592		$	—		$	—	$	214,592
Exchange Term Loan	603,116			(203,116		)	—		400,000
Fairfax Term Loan	300,000			—			—		300,000
2018 Notes	130,987			—			589		131,576
2022 Notes	70,169			—			—		70,169
Deferred financing costs, net	(12,796		)	—			12,796		—
Total debt	$	1,306,068		$	(203,116	)	$	13,385	$	1,116,337

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Summary Of Estimated Fair Value Of Derivative Financial Instruments

The following table presents a summary of the estimated fair value of our derivative financial instruments as of September 30, 2016 and December 31, 2015.

	September 30, 2016
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	(4,135	)	$	—	$	(4,135	)
	December 31, 2015
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	45,592		$	—	$	45,592

Schedule Of Estimated Fair Value Of Other Financial Instruments

The estimated fair values of our 2018 Notes, 2022 Notes, Exchange Term Loan and Fairfax Term Loan are presented below. The estimated fair values of the 2018 Notes and 2022 Notes have been calculated based on quoted prices in active markets. The estimated fair values of the Exchange Term Loan and the Fairfax Term Loan have been calculated based on quoted prices obtained from third-party pricing sources and are classified as Level 2.

	September 30, 2016
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	60,438	$	—	$	—	$	60,438
2022 Notes	27,366		—		—		27,366
Exchange Term Loan	—		263,500		—		263,500
Fairfax Term Loan	—		197,625		—		197,625
	December 31, 2015
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	43,170	$	—	$	—	$	43,170
2022 Notes	48,376		—		—		48,376
Exchange Term Loan	—		278,000		—		278,000
Fairfax Term Loan	—		208,500		—		208,500

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2016

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

For the three and nine months endedSeptember 30, 2016 and 2015, these transactions included the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2016		2015		2016		2015
Amounts received from OPCO	$	3,824	$	7,281	$	12,586	$	23,847

As of September 30, 2016 and December 31, 2015, the amounts owed were as follows:

(in thousands)	September 30, 2016		December 31, 2015
Amounts due to EXCO (1)	$	932	$	1,733
Amounts due from EXCO (1)	12,903		10,410

(1) Advances to OPCO are recorded in "Other current assets" in our Condensed Consolidated Balance Sheets. Any amounts we owe to OPCO are netted against the advance until the advances are utilized. If the advances are fully utilized, we record amounts owed in "Accounts payable and accrued liabilities" in our Condensed Consolidated Balance Sheets.

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Condensed Consolidating Financial Statements (Tables)

9 Months Ended

Sep. 30, 2016

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Schedule Of Condensed Consolidating Balance Sheet

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

September 30, 2016

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	9,754		$	(6,220	)	$	—	$	—		$	3,534
Restricted cash	—			18,434			—		—			18,434
Other current assets	13,233			75,608			—		—			88,841
Total current assets	22,987			87,822			—		—			110,809
Equity investments	—			—			31,973		—			31,973
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	—			93,511			—		—			93,511
Proved developed and undeveloped oil and natural gas properties	331,326			2,615,315			—		—			2,946,641
Accumulated depletion	(330,776		)	(2,359,835		)	—		—			(2,690,611		)
Oil and natural gas properties, net	550			348,991			—		—			349,541
Other property and equipment, net	608			23,450			—		—			24,058
Investments in and advances to affiliates, net	452,896			—			—		(452,896		)	—
Deferred financing costs, net	5,000			—			—		—			5,000
Derivative financial instruments	1,455			—			—		—			1,455
Goodwill	13,293			149,862			—		—			163,155
Total assets	$	496,789		$	610,125		$	31,973	$	(452,896	)	$	685,991
Liabilities and shareholders' equity
Current liabilities	$	74,818		$	167,105		$	—	$	—		$	241,923
Long-term debt	1,256,068			—			—		—			1,256,068
Other long-term liabilities	3,493			22,097			—		—			25,590
Payable to parent	—			2,360,227			—		(2,360,227		)	—
Total shareholders' equity	(837,590		)	(1,939,304		)	31,973		1,907,331			(837,590		)
Total liabilities and shareholders' equity	$	496,789		$	610,125		$	31,973	$	(452,896	)	$	685,991

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2015

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	34,296		$	(22,049	)	$	—	$	—		$	12,247
Restricted cash	2,100			19,120			—		—			21,220
Other current assets	51,133			65,201			—		—			116,334
Total current assets	87,529			62,272			—		—			149,801
Equity investments	—			—			40,797		—			40,797
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	—			115,377			—		—			115,377
Proved developed and undeveloped oil and natural gas properties	330,775			2,739,655			—		—			3,070,430
Accumulated depletion	(330,775		)	(2,296,988		)	—		—			(2,627,763		)
Oil and natural gas properties, net	—			558,044			—		—			558,044
Other property and equipment, net	749			27,063			—		—			27,812
Investments in and advances to affiliates, net	616,940			—			—		(616,940		)	—
Deferred financing costs, net	8,408			—			—		—			8,408
Derivative financial instruments	6,109			—			—		—			6,109
Goodwill	13,293			149,862			—		—			163,155
Total assets	$	733,028		$	797,241		$	40,797	$	(616,940	)	$	954,126
Liabilities and shareholders' equity
Current liabilities	$	74,472		$	178,447		$	—	$	—		$	252,919
Long-term debt	1,320,279			—			—		—			1,320,279
Other long-term liabilities	600			42,651			—		—			43,251
Payable to parent	—			2,276,594			—		(2,276,594		)	—
Total shareholders' equity	(662,323		)	(1,700,451		)	40,797		1,659,654			(662,323		)
Total liabilities and shareholders' equity	$	733,028		$	797,241		$	40,797	$	(616,940	)	$	954,126

Schedule Of Condensed Consolidating Statement Of Operations

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months endedSeptember 30, 2016

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	70,862		$	—		$	—	$	70,862
Purchased natural gas and marketing	—			6,324			—			—		6,324
Total revenues	—			77,186			—			—		77,186
Costs and expenses:
Oil and natural gas production	—			12,608			—			—		12,608
Gathering and transportation	—			27,979			—			—		27,979
Purchased natural gas	—			6,586			—			—		6,586
Depletion, depreciation and amortization	89			15,821			—			—		15,910
Impairment of oil and natural gas properties	—			—			—			—		—
Accretion of discount on asset retirement obligations	—			325			—			—		325
General and administrative	(4,395		)	15,141			—			—		10,746
Other operating items	—			(1,110		)	—			—		(1,110		)
Total costs and expenses	(4,306		)	77,350			—			—		73,044
Operating income (loss)	4,306			(164		)	—			—		4,142
Other income (expense):
Interest expense, net	(16,997		)	—			—					(16,997		)
Gain on derivative financial instruments	8,209			—			—					8,209
Gain on extinguishment of debt	57,421			—			—					57,421
Other income	4			8			—					12
Equity loss	—			—			(823		)			(823		)
Net loss from consolidated subsidiaries	(979		)	—			—			979		—
Total other income (expense)	47,658			8			(823		)	979		47,822
Income (loss) before income taxes	51,964			(156		)	(823		)	979		51,964
Income tax expense	1,028			—			—			—		1,028
Net income (loss)	$	50,936		$	(156	)	$	(823	)	$	979	$	50,936

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months endedSeptember 30, 2015

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	83,744		$	—		$	—	$	83,744
Purchased natural gas and marketing	—			6,773			—			—		6,773
Total revenues	—			90,517			—			—		90,517
Costs and expenses:
Oil and natural gas production	7			18,606			—			—		18,613
Gathering and transportation	—			23,743			—			—		23,743
Purchased natural gas	—			6,991			—			—		6,991
Depletion, depreciation and amortization	229			51,784			—			—		52,013
Impairment of oil and natural gas properties	1,372			338,021			—			—		339,393
Accretion of discount on asset retirement obligations	—			574			—			—		574
General and administrative	(2,345		)	15,738			—			—		13,393
Other operating items	(3		)	(225		)	—			—		(228		)
Total costs and expenses	(740		)	455,232			—			—		454,492
Operating income (loss)	740			(364,715		)	—			—		(363,975		)
Other income (expense):
Interest expense, net	(27,761		)	—			—			—		(27,761		)
Gain on derivative financial instruments	37,348			—			—			—		37,348
Other income	14			7			—			—		21
Equity loss	—			—			(152		)	—		(152		)
Net loss from consolidated subsidiaries	(364,860		)	—			—			364,860		—
Total other income (expense)	(355,259		)	7			(152		)	364,860		9,456
Loss before income taxes	(354,519		)	(364,708		)	(152		)	364,860		(354,519		)
Income tax expense	—			—			—			—		—
Net loss	$	(354,519	)	$	(364,708	)	$	(152	)	$	364,860	$	(354,519	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months endedSeptember 30, 2016

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	176,732		$	—		$	—	$	176,732
Purchased natural gas and marketing	—			15,335			—			—		15,335
Total revenues	—			192,067			—			—		192,067
Costs and expenses:
Oil and natural gas production	4			39,139			—			—		39,143
Gathering and transportation	—			79,828			—			—		79,828
Purchased natural gas	—			17,273			—			—		17,273
Depletion, depreciation and amortization	298			63,697			—			—		63,995
Impairment of oil and natural gas properties	838			159,975			—			—		160,813
Accretion of discount on asset retirement obligations	—			2,006			—			—		2,006
General and administrative	(6,062		)	44,688			—			—		38,626
Other operating items	(406		)	24,342			—			—		23,936
Total costs and expenses	(5,328		)	430,948			—			—		425,620
Operating income (loss)	5,328			(238,881		)	—			—		(233,553		)
Other income (expense):
Interest expense, net	(54,186		)	—			—			—		(54,186		)
Loss on derivative financial instruments	(11,632		)	—			—			—		(11,632		)
Gain on extinguishment of debt	119,374			—			—			—		119,374
Other income	9			28			—			—		37
Equity loss	—			—			(8,824		)	—		(8,824		)
Net loss from consolidated subsidiaries	(247,677		)	—			—			247,677		—
Total other income (expense)	(194,112		)	28			(8,824		)	247,677		44,769
Loss before income taxes	(188,784		)	(238,853		)	(8,824		)	247,677		(188,784		)
Income tax expense	1,775			—			—			—		1,775
Net loss	$	(190,559	)	$	(238,853	)	$	(8,824	)	$	247,677	$	(190,559	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months endedSeptember 30, 2015

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	4		$	264,143		$	—		$	—	$	264,147
Purchased natural gas and marketing	—			21,012			—			—		21,012
Total revenues	4			285,155			—			—		285,159
Costs and expenses:
Oil and natural gas production	30			58,123			—			—		58,153
Gathering and transportation	—			74,243			—			—		74,243
Purchased natural gas	—			21,571			—			—		21,571
Depletion, depreciation and amortization	753			175,407			—			—		176,160
Impairment of oil and natural gas properties	8,263			1,001,784			—			—		1,010,047
Accretion of discount on asset retirement obligations	4			1,694			—			—		1,698
General and administrative	(6,569		)	47,796			—			—		41,227
Other operating items	2,065			(947		)	—			—		1,118
Total costs and expenses	4,546			1,379,671			—			—		1,384,217
Operating loss	(4,542		)	(1,094,516		)	—			—		(1,099,058		)
Other income (expense):
Interest expense, net	(80,822		)	—			—			—		(80,822		)
Gain on derivative financial instruments	54,427			—			—			—		54,427
Other income	87			32			—			—		119
Equity loss	—			—			(1,452		)	—		(1,452		)
Net loss from consolidated subsidiaries	(1,095,936		)	—			—			1,095,936		—
Total other income (expense)	(1,122,244		)	32			(1,452		)	1,095,936		(27,728		)
Loss before income taxes	(1,126,786		)	(1,094,484		)	(1,452		)	1,095,936		(1,126,786		)
Income tax expense	—			—			—			—		—
Net loss	$	(1,126,786	)	$	(1,094,484	)	$	(1,452	)	$	1,095,936	$	(1,126,786	)

Schedule Of Condensed Consolidating Statement Of Cash Flows

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months endedSeptember 30, 2016

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	9,152		$	(12,892	)	$	—	$	—	$	(3,740	)
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(1,250		)	(69,205		)	—		—		(70,455		)
Proceeds from disposition of property and equipment	10			11,232			—		—		11,242
Restricted cash	—			686			—		—		686
Net changes in advances to joint ventures	—			2,377			—		—		2,377
Equity investments and other	—			—			—		—		—
Advances/investments with affiliates	(83,631		)	83,631			—		—		—
Net cash provided by (used in) investing activities	(84,871		)	28,721			—		—		(56,150		)
Financing Activities:
Borrowings under EXCO Resources Credit Agreement	390,897			—			—		—		390,897
Repayments under EXCO Resources Credit Agreement	(243,797		)	—			—		—		(243,797		)
Payments on Exchange Term Loan	(38,056		)	—			—		—		(38,056		)
Repurchases of senior unsecured notes	(53,298		)	—			—		—		(53,298		)
Deferred financing costs and other	(4,569		)	—			—		—		(4,569		)
Net cash provided by financing activities	51,177			—			—		—		51,177
Net increase (decrease) in cash	(24,542		)	15,829			—		—		(8,713		)
Cash at beginning of period	34,296			(22,049		)	—		—		12,247
Cash at end of period	$	9,754		$	(6,220	)	$	—	$	—	$	3,534

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months endedSeptember 30, 2015

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	27,860		$	98,996		$	—	$	—	$	126,856
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(1,784		)	(275,532		)	—		—		(277,316		)
Proceeds from disposition of property and equipment	686			6,711			—		—		7,397
Restricted cash	—			4,016			—		—		4,016
Net changes in advances to joint ventures	—			8,594			—		—		8,594
Equity investments and other	—			1,455			—		—		1,455
Advances/investments with affiliates	(181,813		)	181,813			—		—		—
Net cash used in investing activities	(182,911		)	(72,943		)	—		—		(255,854		)
Financing Activities:
Borrowings under EXCO Resources Credit Agreement	97,500			—			—		—		97,500
Proceeds from issuance of common shares, net	9,829			—			—		—		9,829
Deferred financing costs and other	(4,125		)	—			—		—		(4,125		)
Net cash provided by financing activities	103,204			—			—		—		103,204
Net increase (decrease) in cash	(51,847		)	26,053			—		—		(25,794		)
Cash at beginning of period	86,837			(40,532		)	—		—		46,305
Cash at end of period	$	34,990		$	(14,479	)	$	—	$	—	$	20,511

XML

Organization And Basis Of Presentation (Narrative) (Details) $ in Thousands	3 Months Ended							9 Months Ended
	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Dec. 31, 2014 USD ($)
Cash and cash equivalents	$ 3,534			$ 12,247	$ 20,511			$ 3,534	$ 20,511	$ 46,305
Working Capital Deficit	131,100							131,100
Gathering and transportation	27,979	$ 26,744	$ 25,105		23,743			79,828	74,243
Purchased natural gas and marketing revenues	6,324	4,570	4,441	5,430	6,773	$ 6,678	$ 7,561	15,335	21,012
Purchased natural gas expenses	6,586	4,721	5,966	5,798	6,991	6,862	7,718	17,273	21,571
Natural gas revenues	$ 54,647			42,196	56,300	62,381	65,594	$ 127,044	$ 184,275
OPCO [Member]
Working interest in equity investment								0.50%
Percentage of ownership interest	50.00%							50.00%
East Texas/North Louisiana JV [Member]
Ownership percentage in joint venture	50.00%							50.00%
Appalachia JV [Member]
Ownership percentage in joint venture	50.00%							50.00%
Proportional working interest								49.75%
Revolving Credit Facility [Member] | EXCO Resources Credit Agreement [Member]
Line of Credit Facility, Remaining Borrowing Capacity	$ 75,400							$ 75,400
Current ratio, numerator								1.0
Current ratio, denominator								1.0
Debt Instrument, Covenant, Maximum Ratio of Senior Secured Indebtedness to Consolidated EBITDAX	2.5							2.5
Previously Reported
Gathering and transportation		26,895	26,630
Natural gas revenues				41,828	56,082	62,197	65,437
Revision of third party natural gas purchases and sales
Gathering and transportation		$ (151)	$ (1,525)
Natural gas revenues				$ 368	$ 218	$ 184	$ 157

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Divestitures Divestitures (Details) $ in Thousands				3 Months Ended		6 Months Ended	9 Months Ended
	Oct. 03, 2016 USD ($)	Jul. 01, 2016 USD ($)	May 06, 2016 USD ($) wells	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2016 USD ($) MMcfe	Sep. 30, 2016 USD ($) MMcfe	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from disposition of property and equipment							$ 11,242	$ 7,397
Operating income (loss)				$ 4,142	$ (363,975)		(233,553)	$ (1,099,058)
Asset Retirement Obligation				20,736			$ 20,736		$ 41,648
South Texas divestiture [Member] | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Productive Oil Wells, Number of Wells, Gross | wells			4
Proceeds from disposition of property and equipment			$ 11,500
Pennsylvania divestiture [Member] | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from disposition of property and equipment		$ 100
Sale of Other Property, Plant, and Equipment, Production, Per Day | MMcfe						6
Operating income (loss)						$ (100)
Asset Retirement Obligation						$ 22,600
West Virginia divestiture [Member] | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of Other Property, Plant, and Equipment, Production, Per Day | MMcfe							4
Operating income (loss)							$ 700
Asset Retirement Obligation				$ 9,700			$ 9,700
Subsequent Event [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Reduction in field employees	85.00%
Subsequent Event [Member] | West Virginia divestiture [Member] | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from disposition of property and equipment	$ 4,500

XML

Asset Retirement Obligations (Schedule of Reconciliation of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of period				$ 41,648
Liabilities settled during the period				(59)
Adjustment to liability due to divestitures (1)	[1]			(22,859)
Accretion of discount		$ 325	$ 574	2,006	$ 1,698
Asset retirement obligations at end of period		20,736		20,736
Less current portion		428		428		$ 845
Long-term portion		$ 20,308		$ 20,308

[1] Adjustment to liability due to divestitures is primarily due to the sale of our conventional assets in Pennsylvania on July 1, 2016. See "Note 3. Divestitures" for additional information.

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Oil and Natural Gas Properties (Narrative) (Details)	3 Months Ended			6 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2016 USD ($)	Mar. 31, 2016 $ / bbl $ / MMBTU	Sep. 30, 2015 USD ($)	Jun. 30, 2016 $ / bbl $ / MMBTU	Sep. 30, 2016 USD ($) $ / bbl $ / MMBTU	Sep. 30, 2015 USD ($)	Dec. 31, 2015 $ / bbl $ / MMBTU
Oil and Gas Property [Abstract]
Impairment of unproved costs to proved properties					$ 0	$ 84,900,000.0
Reference prices per mmbtu of natural gas | $ / MMBTU		2.40		2.24	2.24		2.59
Reference Prices Per Bbl Of Oil | $ / bbl		46.26		43.12	41.68		50.28
Impairment of oil and natural gas properties	$ 0		$ 339,393,000		$ 160,813,000	$ 1,010,047,000

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Net income (loss)	$ 50,936	$ (354,519)	$ (190,559)	$ (1,126,786)
Weighted average common shares outstanding	279,873	273,348	279,008	272,147
Net income (loss) per basic common share	$ 0.18	$ (1.30)	$ (0.68)	$ (4.14)
Dilutive Effect of Warrants	0	0	0	0
Weighted average common and common equivalent shares outstanding	281,045	273,348	279,008	272,147
Net income (loss) per diluted common share	$ 0.18	$ (1.30)	$ (0.68)	$ (4.14)
Stock Options [Member]
Dilutive effect of stock equivalents	0	0	0	0
Restricted Stock [Member]
Dilutive effect of stock equivalents	1,172	0	0	0

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Earnings Per Share Earnings Per Share (Details Textual) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	88,083,055	36,157,630	89,522,616	21,200,285

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Derivative Financial Instruments (Fair Value Of Derivative Financial Instruments) (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative financial instruments - Current assets	$ 5,952	$ 39,499
Derivative financial instruments - Long-term assets	1,455	6,109
Derivative financial instruments - Current liabilities	(10,353)	(16)
Derivative financial instruments - Long-term liabilities	(1,189)	0
Net derivative financial instruments	$ (4,135)	$ 45,592

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Derivative Financial Instruments (Effect Of Derivative Financial Instruments) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Gain (loss) on derivative financial instruments	$ 8,209	$ 37,348	$ (11,632)	$ 54,427

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Derivative Financial Instruments (Fair Value Of Oil And Natural Gas Derivative Financial Instruments) (Details) bbl in Thousands, MMBTU in Thousands, $ in Thousands	Sep. 30, 2016 USD ($) MMBTU $ / MMBTU $ / bbl bbl	Dec. 31, 2015 USD ($) MMBTU bbl
Derivatives, Fair Value [Line Items]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net	$ (4,135)	$ 45,592
Oil [Member]
Derivatives, Fair Value [Line Items]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net	$ 2,259
Oil [Member] | Swap [Member]
Derivatives, Fair Value [Line Items]
Volume (oil) | bbl		915
Oil [Member] | Swap [Member] | 2016 [Member]
Derivatives, Fair Value [Line Items]
Volume (oil) | bbl	276
Weighted average strike price per Mmbtu/Bbl | $ / bbl	58.61
Fair Value of Derivative Financial Instruments	$ 2,542
Oil [Member] | Swap [Member] | 2017 [Member]
Derivatives, Fair Value [Line Items]
Volume (oil) | bbl	183
Weighted average strike price per Mmbtu/Bbl | $ / bbl	50.00
Fair Value of Derivative Financial Instrument	$ (283)
Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net	$ (6,394)
Natural Gas [Member] | Swaption [Member] | 2017 [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu | MMBTU	7,300
Weighted average strike price per Mmbtu/Bbl | $ / MMBTU	2.76
Fair Value of Derivative Financial Instrument	$ (2,743)
Natural Gas [Member] | Collar [Member] | 2017 [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu | MMBTU	10,950
Fair Value of Derivative Financial Instrument	$ (420)
Natural Gas [Member] | Collar [Member] | Short [Member] | Call Option [Member] | 2017 [Member]
Derivatives, Fair Value [Line Items]
Weighted average strike price per Mmbtu/Bbl | $ / MMBTU	3.28
Natural Gas [Member] | Collar [Member] | Long [Member] | Put Option [Member] | 2017 [Member]
Derivatives, Fair Value [Line Items]
Weighted average strike price per Mmbtu/Bbl | $ / MMBTU	2.87
Natural Gas [Member] | Swap [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu | MMBTU		49,370
Natural Gas [Member] | Swap [Member] | 2016 [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu | MMBTU	14,260
Weighted average strike price per Mmbtu/Bbl | $ / MMBTU	2.88
Fair Value of Derivative Financial Instrument	$ (1,610)
Natural Gas [Member] | Swap [Member] | 2017 [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu | MMBTU	23,700
Weighted average strike price per Mmbtu/Bbl | $ / MMBTU	2.99
Fair Value of Derivative Financial Instrument	$ (2,440)
Natural Gas [Member] | Swap [Member] | 2018 [Member]
Derivatives, Fair Value [Line Items]
Natural Gas Mmbtu | MMBTU	3,650
Weighted average strike price per Mmbtu/Bbl | $ / MMBTU	3.15
Fair Value of Derivative Financial Instruments	$ 819

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Derivative Financial Instruments (Narrative) (Details) bbl in Thousands, MMBTU in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016 MMBTU $ / MMBTU $ / bbl bbl	Sep. 30, 2015	Sep. 30, 2016 MMBTU $ / MMBTU $ / bbl bbl	Sep. 30, 2015	Dec. 31, 2015 MMBTU bbl
Derivative [Line Items]
Percentage Of Derivative Instruments To Equivalent Production	60.00%	69.00%	55.00%	66.00%
Oil [Member] | 2016 [Member]
Derivative [Line Items]
Derivative, Average Forward Price | $ / bbl	48.53		48.53
Oil [Member] | 2017 [Member]
Derivative [Line Items]
Derivative, Average Forward Price | $ / bbl	51.30		51.30
Oil [Member] | Swap [Member]
Derivative [Line Items]
Investment Contract Volume | bbl					915
Oil [Member] | Swap [Member] | 2016 [Member]
Derivative [Line Items]
Investment Contract Volume | bbl	276		276
Oil [Member] | Swap [Member] | 2017 [Member]
Derivative [Line Items]
Investment Contract Volume | bbl	183		183
Natural Gas [Member] | 2016 [Member]
Derivative [Line Items]
Derivative, Average Forward Price | $ / MMBTU	3.02		3.02
Natural Gas [Member] | 2017 [Member]
Derivative [Line Items]
Derivative, Average Forward Price | $ / MMBTU	3.09		3.09
Natural Gas [Member] | 2018 [Member]
Derivative [Line Items]
Derivative, Average Forward Price | $ / MMBTU	2.91		2.91
Natural Gas [Member] | Swap [Member]
Derivative [Line Items]
Natural gas volume					49,370
Natural Gas [Member] | Swap [Member] | 2016 [Member]
Derivative [Line Items]
Natural gas volume	14,260		14,260
Natural Gas [Member] | Swap [Member] | 2017 [Member]
Derivative [Line Items]
Natural gas volume	23,700		23,700
Natural Gas [Member] | Swap [Member] | 2018 [Member]
Derivative [Line Items]
Natural gas volume	3,650		3,650

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Debt (Schedule Of Long-Term Debt) (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015	Nov. 04, 2015	Oct. 26, 2015
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 1,116,337
Debt Instrument, Deferred Reduction In Carrying Value of Long Term Debt	(203,116)
Deferred financing costs, net	(12,796)	$ (18,294)
Total Debt	1,306,068	1,370,279
Less amounts due within one year	50,000	50,000
Long-term Debt, Excluding Current Maturities	1,256,068	1,320,279
Debt Instrument, Unamortized Discount and Deferred Financing Costs	13,385
Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument	131,576	158,015
Unamortized discount	(589)	(932)
Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	70,169
Debt Instrument	70,169	222,826
Revolving Credit Facility [Member] | EXCO Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Revolving credit facility under credit agreement	214,592	67,492
Senior Notes [Member] | Exchange Term Loan [Member]
Debt Instrument [Line Items]
Secured Debt	603,116	641,172
Debt Instrument, Face Amount	400,000		$ 108,700	$ 291,300
Senior Notes [Member] | Fairfax Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	300,000	$ 300,000
Debt Instrument	300,000
Senior Notes [Member] | Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument	130,987
Senior Notes [Member] | Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument	70,169
Secured Debt [Member] | Exchange Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument	603,116
Debt Instrument, Deferred Reduction In Carrying Value of Long Term Debt	$ (203,116)

XML

Debt Debt (Detailed Summary) (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015	Nov. 04, 2015	Oct. 26, 2015
Debt Instrument [Line Items]
Debt Instrument, Deferred Reduction In Carrying Value of Long Term Debt	$ 203,116
Debt Instrument, Unamortized Discount and Deferred Financing Costs	13,385
Debt Instrument, Face Amount	1,116,337
Deferred financing costs, net	12,796	$ 18,294
Total Debt	1,306,068	1,370,279
Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument	131,576	158,015
Debt Instrument, Unamortized Discount	589	932
Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument	70,169	222,826
Debt Instrument, Face Amount	70,169
Secured Debt [Member] | Exchange Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument	603,116
Debt Instrument, Deferred Reduction In Carrying Value of Long Term Debt	203,116
Senior Notes [Member] | Exchange Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	400,000		$ 108,700	$ 291,300
Senior Notes [Member] | Fairfax Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument	300,000
Debt Instrument, Face Amount	300,000	300,000
Senior Notes [Member] | Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument	130,987
Senior Notes [Member] | Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument	70,169
Revolving Credit Facility [Member] | EXCO Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Revolving credit facility under credit agreement	$ 214,592	$ 67,492

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Debt (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Dec. 31, 2015	Nov. 04, 2015	Oct. 26, 2015
Debt Instrument [Line Items]
Repayments of Unsecured Debt	$ 40,000		$ 53,298	$ 0
Gain on extinguishment of debt	57,421	$ 0	119,374	$ 0
Debt Instrument, Face Amount	$ 1,116,337		$ 1,116,337		$ 1,116,337
Repurchase price of Exchange Term Loan	101.00%		101.00%		101.00%
Fairfax Term Loan [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate								12.50%
Debt Instrument, Face Amount	$ 300,000		$ 300,000		$ 300,000	$ 300,000
Debt instrument, covenant, maximum priority borrowing capacity	500,000		500,000		500,000
Debt Instrument, Covenant, Priority Borrowing Capacity	375,000		375,000		375,000
Debt instrument, principal outstanding	300,000		300,000		300,000
Exchange Term Loan [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate								12.50%
Debt Instrument, Face Amount	400,000		400,000		400,000		$ 108,700	$ 291,300
Debt instrument, covenant, maximum priority borrowing capacity	$ 375,000		$ 375,000		$ 375,000
Debt instrument, covenant, maximum percentage of modified adjusted consolidated net tangible assets	30.00%		30.00%		30.00%
Debt instrument, covenant, maximum borrowing capacity for all second liens of indebtedness	$ 700,000		$ 700,000		$ 700,000
Debt instrument, covenant, coverage ratio, maximum for unsecured borrowings	2.25		2.25		2.25
Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	7.50%		7.50%		7.50%
Repayments of Unsecured Debt					$ 18,800
Debt Instrument, Amount Exchanged						551,200
Debt Instrument, Repurchased Face Amount	$ 67,200		$ 67,200		67,200
Debt instrument, principal outstanding	131,576		131,576		131,576	158,015
Senior Unsecured Notes due 2018 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument, principal outstanding	$ 130,987		$ 130,987		$ 130,987
Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	8.50%		8.50%		8.50%
Repayments of Unsecured Debt					$ 46,500
Debt Instrument, Face Amount	$ 70,169		$ 70,169		70,169
Debt Instrument, Amount Exchanged						277,200
Debt Instrument, Repurchased Face Amount	152,700		152,700		152,700
Debt instrument, principal outstanding	$ 70,169		$ 70,169		$ 70,169	222,826
Debt instrument, issued price, percentage	100.00%		100.00%		100.00%
Senior Unsecured Notes due 2022 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument, principal outstanding	$ 70,169		$ 70,169		$ 70,169
Revolving Credit Facility [Member] | EXCO Resources Credit Agreement [Member]
Debt Instrument [Line Items]
Outstanding indebtedness	214,592		214,592		214,592	$ 67,492
Line of Credit Facility, Maximum Borrowing Capacity	325,000		325,000		325,000
Current borrowing capacity	300,000		300,000		300,000
Line of Credit Facility, Remaining Borrowing Capacity	$ 75,400		$ 75,400		$ 75,400
Line of credit facility, maturity date			Jul. 31, 2018
Line of Credit Facility, Interest Rate at Period End	4.00%		4.00%		4.00%
Current ratio, numerator			1.0
Current ratio, denominator			1.0
Debt instrument, covenant, minimum ratio of consolidated EBITDAX to consolidated interest expense	1.25		1.25		1.25
Debt Instrument, Covenant, Maximum Ratio of Senior Secured Indebtedness to Consolidated EBITDAX	2.5		2.5		2.5
Revolving Credit Facility [Member] | EXCO Resources Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			2.25%
Revolving Credit Facility [Member] | EXCO Resources Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			3.25%
Revolving Credit Facility [Member] | EXCO Resources Credit Agreement [Member] | Alternate Base Rate (ABR) [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			1.25%
Revolving Credit Facility [Member] | EXCO Resources Credit Agreement [Member] | Alternate Base Rate (ABR) [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			2.25%
Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount			$ 26,400
Senior Unsecured Notes due 2022 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 101,300		$ 152,700

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Commitments and contingencies (Details) MMBTU in Thousands, $ in Millions	1 Months Ended	3 Months Ended		6 Months Ended	9 Months Ended	12 Months Ended
	Jun. 30, 2016 bbl	Sep. 30, 2016 USD ($) MMBTU $ / MMBTU	Mar. 31, 2016 $ / MMBTU	Jun. 30, 2016 $ / MMBTU	Sep. 30, 2016 USD ($) $ / MMBTU	Dec. 31, 2015 $ / MMBTU
Loss Contingencies [Line Items]
Reservation fees 75,000 mmbtu			2.40	2.24	2.24	2.59
Eagle Ford joint venture partner [Member]
Loss Contingencies [Line Items]
Transfered Interest, Net Production of Oil, Per Day | bbl	350
Enterprise Products Operating LLC and Acadian Gas Pipeline System Case
Loss Contingencies [Line Items]
Natural gas, volume, reservation fees $0.25 | MMBTU		150
Reservation fees150,000 mmbtu		0.25
Natural gas, volume, reservation fees $0.20 | MMBTU		175
Reservation fees175,000 mmbtu		0.20
Amount that can be sold per agreement | MMBTU		75
Reservation fees 75,000 mmbtu		0.25
Enterprise Products Operating LLC | Enterprise Products Operating LLC and Acadian Gas Pipeline System Case
Loss Contingencies [Line Items]
Receivables | $		$ 6.4			$ 6.4
Accrued termination costs | $		$ 2.1			$ 2.1

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Fair Value Measurements (Narrative) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Jul. 25, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Accounts Payable and Accrued Liabilities, Current	$ 56,056		$ 88,049
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cost-method Investments, Other than Temporary Impairment	$ 4,900
Eagle Ford joint venture partner [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of assets transferred		$ 23,200

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Fair Value Measurements (Summary Of Estimated Fair Value Of Derivative Financial Instruments) (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net	$ (4,135)	$ 45,592
Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net	0	0
Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net	(4,135)	45,592
Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net	$ 0	$ 0

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Fair Value Measurements (Schedule Of Estimated Fair Value Of Other Financial Instruments) (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Senior Unsecured Notes due 2018 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$ 60,438	$ 43,170
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	60,438	43,170
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	27,366	48,376
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	27,366	48,376
Senior Unsecured Notes due 2022 [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0	0
Senior Unsecured Notes due 2022 [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0	0
Exchange Term Loan [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	263,500	278,000
Exchange Term Loan [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0	0
Exchange Term Loan [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	263,500	278,000
Exchange Term Loan [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0	0
Fairfax Term Loan [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	197,625	208,500
Fairfax Term Loan [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	0	0
Fairfax Term Loan [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	197,625	208,500
Fairfax Term Loan [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$ 0	$ 0

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Income Taxes (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($)
Income Tax Disclosure [Abstract]
Change in valuation allowance	$ 69.4
Recognized net valuation allowance	$ 1,400.0

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Related Party Transactions (Details) - OPCO [Member] - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Advances to OPCO		$ 0	$ 0	$ 0	$ 0
Amounts received from OPCO		3,824	$ 7,281	12,586	$ 23,847
Amounts due to EXCO	[1]	932		932		$ 1,733
Amounts due from EXCO	[1]	$ 12,903		$ 12,903		$ 10,410

[1] Advances to OPCO are recorded in "Other current assets" in our Condensed Consolidated Balance Sheets. Any amounts we owe to OPCO are netted against the advance until the advances are utilized. If the advances are fully utilized, we record amounts owed in "Accounts payable and accrued liabilities" in our Condensed Consolidated Balance Sheets.

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Related Party Transactions Related Party Transactions (Narrative) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Equity-based compensation related to warrants	$ 900,000	$ 200,000	$ 11,800,000	$ 200,000
Fairfax [Member]
Related Party Transaction [Line Items]
beneficial ownership of outstanding common shares	9.00%		9.00%
Ownership of principal amount of Exchange Term Loan, amount	$ 112,100,000		$ 112,100,000
Energy Strategic Advisory Services LLC (ESAS) [Member]
Related Party Transaction [Line Items]
beneficial ownership of outstanding common shares					6.50%
Services and Investment Agreement, Monthly Fee	300,000		300,000
Services and Investment Agreement, Annual Incentive Payment	2,400,000		2,400,000
Payments to related party	7,200,000
Accounts Payable, Related Parties, Current	$ 900,000		$ 900,000		$ 4,500,000
Class of Warrant or Right, Number of Securities Called by Warrants or Rights	80,000,000		80,000,000
Ownership of principal amount of Exchange Term Loan, amount	$ 47,900,000		$ 47,900,000
75th Percentile or Above of Peer Group [Member] | Energy Strategic Advisory Services LLC (ESAS) [Member]
Related Party Transaction [Line Items]
Services and Investment Agreement, Annual Incentive Payment	2,400,000		2,400,000
Below 75th Percentile of Peer Group [Member] | Energy Strategic Advisory Services LLC (ESAS) [Member]
Related Party Transaction [Line Items]
Services and Investment Agreement, Annual Incentive Payment	$ 600,000		$ 600,000

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Condensed Consolidating Financial Statements (Schedule Of Condensed Consolidating Balance Sheet) (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 3,534	$ 12,247	$ 20,511	$ 46,305
Restricted cash	18,434	21,220
Other current assets	88,841	116,334
Total current assets	110,809	149,801
Equity investments	31,973	40,797
Unproved oil and natural gas properties and development costs not being amortized	93,511	115,377
Proved developed and undeveloped oil and natural gas properties	2,946,641	3,070,430
Accumulated depletion	(2,690,611)	(2,627,763)
Oil and natural gas properties, net	349,541	558,044
Other property and equipment, net	24,058	27,812
Investments in and advances to affiliates, net	0	0
Deferred financing costs, net	5,000	8,408
Derivative financial instruments	1,455	6,109
Goodwill	163,155	163,155
Total assets	685,991	954,126
Liabilities and shareholders’ equity
Current liabilities	241,923	252,919
Long-term debt	1,256,068	1,320,279
Other long-term liabilities	25,590	43,251
Payable to parent	0	0
Total shareholders' equity	(837,590)	(662,323)	(600,476)	510,004
Total liabilities and shareholders' equity	685,991	954,126
Resources [Member]
Current assets:
Cash and cash equivalents	9,754	34,296	34,990	86,837
Restricted cash	0	2,100
Other current assets	13,233	51,133
Total current assets	22,987	87,529
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	331,326	330,775
Accumulated depletion	(330,776)	(330,775)
Oil and natural gas properties, net	550	0
Other property and equipment, net	608	749
Investments in and advances to affiliates, net	452,896	616,940
Deferred financing costs, net	5,000	8,408
Derivative financial instruments	1,455	6,109
Goodwill	13,293	13,293
Total assets	496,789	733,028
Liabilities and shareholders’ equity
Current liabilities	74,818	74,472
Long-term debt	1,256,068	1,320,279
Other long-term liabilities	3,493	600
Payable to parent	0	0
Total shareholders' equity	(837,590)	(662,323)
Total liabilities and shareholders' equity	496,789	733,028
Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	(6,220)	(22,049)	(14,479)	(40,532)
Restricted cash	18,434	19,120
Other current assets	75,608	65,201
Total current assets	87,822	62,272
Equity investments	0	0
Unproved oil and natural gas properties and development costs not being amortized	93,511	115,377
Proved developed and undeveloped oil and natural gas properties	2,615,315	2,739,655
Accumulated depletion	(2,359,835)	(2,296,988)
Oil and natural gas properties, net	348,991	558,044
Other property and equipment, net	23,450	27,063
Investments in and advances to affiliates, net	0	0
Deferred financing costs, net	0	0
Derivative financial instruments	0	0
Goodwill	149,862	149,862
Total assets	610,125	797,241
Liabilities and shareholders’ equity
Current liabilities	167,105	178,447
Long-term debt	0	0
Other long-term liabilities	22,097	42,651
Payable to parent	2,360,227	2,276,594
Total shareholders' equity	(1,939,304)	(1,700,451)
Total liabilities and shareholders' equity	610,125	797,241
Non-Guarantor Subsidiaries [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	31,973	40,797
Unproved oil and natural gas properties and development costs not being amortized	0	0
Proved developed and undeveloped oil and natural gas properties	0	0
Accumulated depletion	0	0
Oil and natural gas properties, net	0	0
Other property and equipment, net	0	0
Investments in and advances to affiliates, net	0	0
Deferred financing costs, net	0	0
Derivative financial instruments	0	0
Goodwill	0	0
Total assets	31,973	40,797
Liabilities and shareholders’ equity
Current liabilities	0	0
Long-term debt	0	0
Other long-term liabilities	0	0
Payable to parent	0	0
Total shareholders' equity	31,973	40,797
Total liabilities and shareholders' equity	31,973	40,797
Consolidation, Eliminations [Member]
Current assets:
Cash and cash equivalents	0	0	$ 0	$ 0
Restricted cash	0	0
Other current assets	0	0
Total current assets	0	0
Equity investments	0	0
Unproved oil and natural gas properties and development costs not being amortized	0	0
Proved developed and undeveloped oil and natural gas properties	0	0
Accumulated depletion	0	0
Oil and natural gas properties, net	0	0
Other property and equipment, net	0	0
Investments in and advances to affiliates, net	(452,896)	(616,940)
Deferred financing costs, net	0	0
Derivative financial instruments	0	0
Goodwill	0	0
Total assets	(452,896)	(616,940)
Liabilities and shareholders’ equity
Current liabilities	0	0
Long-term debt	0	0
Other long-term liabilities	0	0
Payable to parent	(2,360,227)	(2,276,594)
Total shareholders' equity	1,907,331	1,659,654
Total liabilities and shareholders' equity	$ (452,896)	$ (616,940)

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Condensed Consolidating Financial Statements (Schedule Of Condensed Consolidating Statement Of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended							9 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Sep. 30, 2016	Sep. 30, 2015
Oil and natural gas	$ 70,862				$ 83,744			$ 176,732	$ 264,147
Purchased natural gas and marketing	6,324	$ 4,570	$ 4,441	$ 5,430	6,773	$ 6,678	$ 7,561	15,335	21,012
Total revenues	77,186				90,517			192,067	285,159
Oil and natural gas production	12,608				18,613			39,143	58,153
Gathering and transportation	27,979	26,744	25,105		23,743			79,828	74,243
Purchased natural gas	6,586	$ 4,721	$ 5,966	$ 5,798	6,991	$ 6,862	$ 7,718	17,273	21,571
Depletion, depreciation and amortization	15,910				52,013			63,995	176,160
Impairment of oil and natural gas properties	0				339,393			160,813	1,010,047
Accretion of discount on asset retirement obligations	325				574			2,006	1,698
General and administrative	10,746				13,393			38,626	41,227
Other operating items	(1,110)				(228)			23,936	1,118
Total costs and expenses	73,044				454,492			425,620	1,384,217
Operating income (loss)	4,142				(363,975)			(233,553)	(1,099,058)
Interest expense, net	(16,997)				(27,761)			(54,186)	(80,822)
Gain (loss) on derivative financial instruments	8,209				37,348			(11,632)	54,427
Gain on extinguishment of debt	57,421				0			119,374	0
Other income (loss)	12				21			37	119
Equity loss	(823)				(152)			(8,824)	(1,452)
Net earnings (loss) from consolidated subsidiaries	0				0			0	0
Total other income (expense)	47,822				9,456			44,769	(27,728)
Income (loss) before income taxes	51,964				(354,519)			(188,784)	(1,126,786)
Income tax expense	1,028				0			1,775	0
Net income (loss)	50,936				(354,519)			(190,559)	(1,126,786)
Resources [Member]
Oil and natural gas	0				0			0	4
Purchased natural gas and marketing	0				0			0	0
Total revenues	0				0			0	4
Oil and natural gas production	0				7			4	30
Gathering and transportation	0				0			0	0
Purchased natural gas	0				0			0	0
Depletion, depreciation and amortization	89				229			298	753
Impairment of oil and natural gas properties	0				1,372			838	8,263
Accretion of discount on asset retirement obligations	0				0			0	4
General and administrative	(4,395)				(2,345)			(6,062)	(6,569)
Other operating items	0				(3)			(406)	2,065
Total costs and expenses	(4,306)				(740)			(5,328)	4,546
Operating income (loss)	4,306				740			5,328	(4,542)
Interest expense, net	(16,997)				(27,761)			(54,186)	(80,822)
Gain (loss) on derivative financial instruments	8,209				37,348			(11,632)	54,427
Gain on extinguishment of debt	57,421							119,374
Other income (loss)	4				14			9	87
Equity loss	0				0			0	0
Net earnings (loss) from consolidated subsidiaries	(979)				(364,860)			(247,677)	(1,095,936)
Total other income (expense)	47,658				(355,259)			(194,112)	(1,122,244)
Income (loss) before income taxes	51,964				(354,519)			(188,784)	(1,126,786)
Income tax expense	1,028				0			1,775	0
Net income (loss)	50,936				(354,519)			(190,559)	(1,126,786)
Guarantor Subsidiaries [Member]
Oil and natural gas	70,862				83,744			176,732	264,143
Purchased natural gas and marketing	6,324				6,773			15,335	21,012
Total revenues	77,186				90,517			192,067	285,155
Oil and natural gas production	12,608				18,606			39,139	58,123
Gathering and transportation	27,979				23,743			79,828	74,243
Purchased natural gas	6,586				6,991			17,273	21,571
Depletion, depreciation and amortization	15,821				51,784			63,697	175,407
Impairment of oil and natural gas properties	0				338,021			159,975	1,001,784
Accretion of discount on asset retirement obligations	325				574			2,006	1,694
General and administrative	15,141				15,738			44,688	47,796
Other operating items	(1,110)				(225)			24,342	(947)
Total costs and expenses	77,350				455,232			430,948	1,379,671
Operating income (loss)	(164)				(364,715)			(238,881)	(1,094,516)
Interest expense, net	0				0			0	0
Gain (loss) on derivative financial instruments	0				0			0	0
Gain on extinguishment of debt	0							0
Other income (loss)	8				7			28	32
Equity loss	0				0			0	0
Net earnings (loss) from consolidated subsidiaries	0				0			0	0
Total other income (expense)	8				7			28	32
Income (loss) before income taxes	(156)				(364,708)			(238,853)	(1,094,484)
Income tax expense	0				0			0	0
Net income (loss)	(156)				(364,708)			(238,853)	(1,094,484)
Non-Guarantor Subsidiaries [Member]
Oil and natural gas	0				0			0	0
Purchased natural gas and marketing	0				0			0	0
Total revenues	0				0			0	0
Oil and natural gas production	0				0			0	0
Gathering and transportation	0				0			0	0
Purchased natural gas	0				0			0	0
Depletion, depreciation and amortization	0				0			0	0
Impairment of oil and natural gas properties	0				0			0	0
Accretion of discount on asset retirement obligations	0				0			0	0
General and administrative	0				0			0	0
Other operating items	0				0			0	0
Total costs and expenses	0				0			0	0
Operating income (loss)	0				0			0	0
Interest expense, net	0				0			0	0
Gain (loss) on derivative financial instruments	0				0			0	0
Gain on extinguishment of debt	0							0
Other income (loss)	0				0			0	0
Equity loss	(823)				(152)			(8,824)	(1,452)
Net earnings (loss) from consolidated subsidiaries	0				0			0	0
Total other income (expense)	(823)				(152)			(8,824)	(1,452)
Income (loss) before income taxes	(823)				(152)			(8,824)	(1,452)
Income tax expense	0				0			0	0
Net income (loss)	(823)				(152)			(8,824)	(1,452)
Consolidation, Eliminations [Member]
Oil and natural gas	0				0			0	0
Purchased natural gas and marketing	0				0			0	0
Total revenues	0				0			0	0
Oil and natural gas production	0				0			0	0
Gathering and transportation	0				0			0	0
Purchased natural gas	0				0			0	0
Depletion, depreciation and amortization	0				0			0	0
Impairment of oil and natural gas properties	0				0			0	0
Accretion of discount on asset retirement obligations	0				0			0	0
General and administrative	0				0			0	0
Other operating items	0				0			0	0
Total costs and expenses	0				0			0	0
Operating income (loss)	0				0			0	0
Interest expense, net					0			0	0
Gain (loss) on derivative financial instruments					0			0	0
Gain on extinguishment of debt								0
Other income (loss)					0			0	0
Equity loss					0			0	0
Net earnings (loss) from consolidated subsidiaries	979				364,860			247,677	1,095,936
Total other income (expense)	979				364,860			247,677	1,095,936
Income (loss) before income taxes	979				364,860			247,677	1,095,936
Income tax expense	0				0			0	0
Net income (loss)	$ 979				$ 364,860			$ 247,677	$ 1,095,936

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Condensed Consolidating Financial Statements (Schedule Of Condensed Consolidating Statement Of Cash Flows) (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016
Net cash provided by (used in) operating activities		$ (3,740)	$ 126,856
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions		(70,455)	(277,316)
Proceeds from disposition of property and equipment		11,242	7,397
Restricted cash		686	4,016
Net changes in advances to joint ventures		2,377	8,594
Equity investments and other		0	1,455
Advances/investments with affiliates		0	0
Net cash used in investing activities		(56,150)	(255,854)
Borrowings under EXCO Resources Credit Agreement		390,897	97,500
Proceeds from issuance of common shares, net		0	9,829
Repayments under EXCO Resources Credit Agreement		(243,797)	0
Payments on Exchange Term Loan		(38,056)	0
Repurchases of senior unsecured notes	$ (40,000)	(53,298)	0
Deferred financing costs and other		(4,569)	(4,125)
Net cash provided by financing activities		51,177	103,204
Net decrease in cash		(8,713)	(25,794)
Cash at beginning of period		12,247	46,305	$ 20,511
Cash at end of period	3,534	3,534	20,511	3,534
Resources [Member]
Net cash provided by (used in) operating activities		9,152	27,860
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions		(1,250)	(1,784)
Proceeds from disposition of property and equipment		10	686
Restricted cash		0	0
Net changes in advances to joint ventures		0	0
Equity investments and other		0	0
Advances/investments with affiliates		(83,631)	(181,813)
Net cash used in investing activities		(84,871)	(182,911)
Borrowings under EXCO Resources Credit Agreement		390,897	97,500
Proceeds from issuance of common shares, net			9,829
Repayments under EXCO Resources Credit Agreement		(243,797)
Payments on Exchange Term Loan		(38,056)
Repurchases of senior unsecured notes		(53,298)
Deferred financing costs and other		(4,569)	(4,125)
Net cash provided by financing activities		51,177	103,204
Net decrease in cash		(24,542)	(51,847)
Cash at beginning of period		34,296	86,837	34,990
Cash at end of period	9,754	9,754	34,990	9,754
Guarantor Subsidiaries [Member]
Net cash provided by (used in) operating activities		(12,892)	98,996
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions		(69,205)	(275,532)
Proceeds from disposition of property and equipment		11,232	6,711
Restricted cash		686	4,016
Net changes in advances to joint ventures		2,377	8,594
Equity investments and other		0	1,455
Advances/investments with affiliates		83,631	181,813
Net cash used in investing activities		28,721	(72,943)
Borrowings under EXCO Resources Credit Agreement		0	0
Proceeds from issuance of common shares, net			0
Repayments under EXCO Resources Credit Agreement		0
Payments on Exchange Term Loan		0
Repurchases of senior unsecured notes		0
Deferred financing costs and other		0	0
Net cash provided by financing activities		0	0
Net decrease in cash		15,829	26,053
Cash at beginning of period		(22,049)	(40,532)	(14,479)
Cash at end of period	(6,220)	(6,220)	(14,479)	(6,220)
Non-Guarantor Subsidiaries [Member]
Net cash provided by (used in) operating activities		0	0
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions		0	0
Proceeds from disposition of property and equipment		0	0
Restricted cash		0	0
Net changes in advances to joint ventures		0	0
Equity investments and other		0	0
Advances/investments with affiliates		0	0
Net cash used in investing activities		0	0
Borrowings under EXCO Resources Credit Agreement		0	0
Proceeds from issuance of common shares, net			0
Repayments under EXCO Resources Credit Agreement		0
Payments on Exchange Term Loan		0
Repurchases of senior unsecured notes		0
Deferred financing costs and other		0	0
Net cash provided by financing activities		0	0
Net decrease in cash		0	0
Cash at beginning of period		0	0	0
Cash at end of period	0	0	0	0
Consolidation, Eliminations [Member]
Net cash provided by (used in) operating activities		0	0
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions		0	0
Proceeds from disposition of property and equipment		0	0
Restricted cash		0	0
Net changes in advances to joint ventures		0	0
Equity investments and other		0	0
Advances/investments with affiliates		0	0
Net cash used in investing activities		0	0
Borrowings under EXCO Resources Credit Agreement		0	0
Proceeds from issuance of common shares, net			0
Repayments under EXCO Resources Credit Agreement		0
Payments on Exchange Term Loan		0
Repurchases of senior unsecured notes		0
Deferred financing costs and other		0	0
Net cash provided by financing activities		0	0
Net decrease in cash		0	0
Cash at beginning of period		0	0	0
Cash at end of period	$ 0	$ 0	$ 0	$ 0