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 ~~June~~September 30, 2016



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):

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 ~~July~~October 28, 2016 was ~~282,776,414.~~282,445,821.

Table of Contents

EXCO RESOURCES, INC.

INDEX



PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	2
	Condensed Consolidated Balance Sheets at ~~June~~September 30, 2016 and December 31, 2015	2
	Condensed Consolidated Statements of Operations for the Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2016 and 2015	3
	Condensed Consolidated Statements of Cash Flows for the ~~Six~~Nine Months Ended ~~June~~September 30, 2016 and 2015	4
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the ~~Six~~Nine Months Ended ~~June~~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	3132
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4851
Item 4.	Controls and Procedures	4852

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	4952
Item 1A.	Risk Factors	52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4953
Item 6.	Exhibits	4953
	Signatures	5054

PART I—FINANCIAL INFORMATION


Item 1.	Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS


(in thousands)	June 30, 2016			December 31, 2015			September 30, 2016			December 31, 2015
	(Unaudited)						(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	27,563		$	12,247		$	3,534		$	12,247
Restricted cash	25,485			21,220			18,434			21,220
Accounts receivable, net:
Oil and natural gas	7,447			37,236			53,439			37,236
Joint interest	15,520			22,095			17,949			22,095
Other	3,359			8,894			3,871			8,894
Derivative financial instruments	8,686			39,499			5,952			39,499
Inventory and other	7,228			8,610			7,630			8,610
Total current assets	95,288			149,801			110,809			149,801
Equity investments	32,796			40,797			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	96,147			115,377			93,511			115,377
Proved developed and undeveloped oil and natural gas properties	2,975,428			3,070,430			2,946,641			3,070,430
Accumulated depletion	(2,675,083		)	(2,627,763		)	(2,690,611		)	(2,627,763		)
Oil and natural gas properties, net	396,492			558,044			349,541			558,044
Other property and equipment, net	25,242			27,812			24,058			27,812
Deferred financing costs, net	5,891			8,408			5,000			8,408
Derivative financial instruments	1,572			6,109			1,455			6,109
Goodwill	163,155			163,155			163,155			163,155
Total assets	$	720,436		$	954,126		$	685,991		$	954,126
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	92,704		$	88,049		$	56,056		$	88,049
Revenues and royalties payable	122,835			106,163			121,312			106,163
Accrued interest payable	6,311			7,846			3,774			7,846
Current portion of asset retirement obligations	845			845			428			845
Income taxes payable	—			—			—			—
Derivative financial instruments	15,559			16			10,353			16
Current maturities of long-term debt	50,000			50,000			50,000			50,000
Total current liabilities	288,254			252,919			241,923			252,919
Long-term debt	1,274,437			1,320,279			1,256,068			1,320,279
Deferred income taxes	747			—			1,775			—
Derivative financial instruments	2,335			—			1,189			—
Asset retirement obligations and other long-term liabilities	44,867			43,251			22,626			43,251
Shareholders’ equity:
Common shares, $0.001 par value; 780,000,000 authorized shares; 283,134,228 shares issued and 282,539,565 shares outstanding at June 30, 2016; 283,633,996 shares issued and 283,039,333 shares outstanding at December 31, 2015	276			276
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	3,535,747			3,522,153			3,537,393			3,522,153
Accumulated deficit	(4,418,595		)	(4,177,120		)	(4,367,634		)	(4,177,120		)
Treasury shares, at cost; 594,663 shares at June 30, 2016 and December 31, 2015	(7,632		)	(7,632		)
Treasury shares, at cost; 594,663 shares at September 30, 2016 and December 31, 2015							(7,632		)	(7,632		)
Total shareholders’ equity	(890,204		)	(662,323		)	(837,590		)	(662,323		)
Total liabilities and shareholders’ equity	$	720,436		$	954,126		$	685,991		$	954,126

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands, except per share data)	2016			2015			2016			2015			2016			2015			2016			2015
Revenues:
Oil	$	17,990		$	31,545		$	33,473		$	52,428		$	16,215		$	27,444		$	49,688		$	79,872
Natural gas	36,231			62,197			72,397			127,634			54,647			56,300			127,044			184,275
Purchased natural gas and marketing													6,324			6,773			15,335			21,012
Total revenues	54,221			93,742			105,870			180,062			77,186			90,517			192,067			285,159
Costs and expenses:
Oil and natural gas operating costs	7,560			14,135			17,038			29,076			8,797			12,669			25,835			41,745
Production and ad valorem taxes	4,857			5,603			9,497			10,464			3,811			5,944			13,308			16,408
Gathering and transportation	26,895			24,785			53,525			50,500			27,979			23,743			79,828			74,243
Purchased natural gas													6,586			6,991			17,273			21,571
Depletion, depreciation and amortization	19,084			61,658			48,085			124,147			15,910			52,013			63,995			176,160
Impairment of oil and natural gas properties	26,214			394,327			160,813			670,654			—			339,393			160,813			1,010,047
Accretion of discount on asset retirement obligations	769			568			1,681			1,124			325			574			2,006			1,698
General and administrative	16,983			12,597			27,880			27,834			10,746			13,393			38,626			41,227
Other operating items	24,856			1,534			25,046			1,346			(1,110		)	(228		)	23,936			1,118
Total costs and expenses	127,218			515,207			343,565			915,145			73,044			454,492			425,620			1,384,217
Operating loss	(72,997		)	(421,465		)	(237,695		)	(735,083		)
Operating income (loss)													4,142			(363,975		)	(233,553		)	(1,099,058		)
Other income (expense):
Interest expense, net	(17,932		)	(25,571		)	(37,189		)	(53,061		)	(16,997		)	(27,761		)	(54,186		)	(80,822		)
Gain (loss) on derivative financial instruments	(36,432		)	(6,631		)	(19,841		)	17,079			8,209			37,348			(11,632		)	54,427
Gain on extinguishment of debt	16,839			—			61,953			—			57,421			—			119,374			—
Other income	13			47			25			98			12			21			37			119
Equity loss	(91		)	(535		)	(8,001		)	(1,300		)	(823		)	(152		)	(8,824		)	(1,452		)
Total other expense	(37,603		)	(32,690		)	(3,053		)	(37,184		)
Loss before income taxes	(110,600		)	(454,155		)	(240,748		)	(772,267		)
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	747			—			747			—			1,028			—			1,775			—
Net loss	$	(111,347	)	$	(454,155	)	$	(241,495	)	$	(772,267	)
Loss per common share:
Net income (loss)													$	50,936		$	(354,519	)	$	(190,559	)	$	(1,126,786	)
Earnings (loss) per common share:
Basic:
Net loss	$	(0.40	)	$	(1.67	)	$	(0.87	)	$	(2.84	)
Net income (loss)													$	0.18		$	(1.30	)	$	(0.68	)	$	(4.14	)
Weighted average common shares outstanding	278,783			271,549			278,570			271,536			279,873			273,348			279,008			272,147
Diluted:
Net loss	$	(0.40	)	$	(1.67	)	$	(0.87	)	$	(2.84	)
Net income (loss)													$	0.18		$	(1.30	)	$	(0.68	)	$	(4.14	)
Weighted average common shares and common share equivalents outstanding	278,783			271,549			278,570			271,536			281,045			273,348			279,008			272,147

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,						Nine Months Ended September 30,
(in thousands)	2016			2015			2016			2015
Operating Activities:
Net loss	$	(241,495	)	$	(772,267	)	$	(190,559	)	$	(1,126,786	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Deferred income tax expense	747			—			1,775			—
Depletion, depreciation and amortization	48,085			124,147			63,995			176,160
Equity-based compensation expense	13,141			3,119			14,558			4,045
Accretion of discount on asset retirement obligations	1,681			1,124			2,006			1,698
Impairment of oil and natural gas properties	160,813			670,654			160,813			1,010,047
Loss from equity investments	8,001			1,300			8,824			1,452
(Gain) loss on derivative financial instruments	19,841			(17,079		)	11,632			(54,427		)
Cash receipts of derivative financial instruments	33,388			57,039			38,097			88,977
Amortization of deferred financing costs and discount on debt issuance	4,999			6,975			7,250			11,083
Other non-operating items	25,151			—			24,068			(13		)
Gain on extinguishment of debt	(61,953		)	—			(119,374		)	—
Effect of changes in:
Restricted cash with related party	(2,101		)	(600		)	2,100			(1,500		)
Accounts receivable	37,633			50,758			(12,752		)	59,238
Other current assets	183			790			(1,207		)	1,062
Accounts payable and other liabilities	(2,189		)	(17,756		)	(14,966		)	(44,180		)
Net cash provided by operating activities	45,925			108,204
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	(54,963		)	(204,600		)	(70,455		)	(269,708		)
Property acquisitions	—			(7,608		)	—			(7,608		)
Proceeds from disposition of property and equipment	11,490			7,397			11,242			7,397
Restricted cash	(2,164		)	6,989			686			4,016
Net changes in advances to joint ventures	2,404			5,756			2,377			8,594
Equity investments and other	—			(503		)	—			1,455
Net cash used in investing activities	(43,233		)	(192,569		)	(56,150		)	(255,854		)
Financing Activities:
Borrowings under EXCO Resources Credit Agreement	297,897			90,000			390,897			97,500
Repayments under EXCO Resources Credit Agreement	(243,797		)	—			(243,797		)	—
Payments on Exchange Term Loan	(25,278		)	—			(38,056		)	—
Repurchases of senior unsecured notes	(13,299		)	—			(53,298		)	—
Proceeds from issuance of common shares, net							—			9,829
Deferred financing costs and other	(2,899		)	(2,033		)	(4,569		)	(4,125		)
Net cash provided by financing activities	12,624			87,967			51,177			103,204
Net increase in cash	15,316			3,602
Net decrease in cash							(8,713		)	(25,794		)
Cash at beginning of period	12,247			46,305			12,247			46,305
Cash at end of period	$	27,563		$	49,907		$	3,534		$	20,511
Supplemental Cash Flow Information:
Cash interest payments	$	33,699		$	52,069		$	51,975		$	81,913
Income tax payments	—			—			—			—
Supplemental non-cash investing and financing activities:
Capitalized equity-based compensation	$	207		$	1,936		$	432		$	2,861
Capitalized interest	2,642			7,027			3,939			10,121

See accompanying notes.

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				Common shares					Treasury shares						Additional paid-in capital			Accumulated deficit				Total shareholders’ equity
(in thousands)	Shares		Amount		Shares		Amount							Accumulated deficit			Shares					Amount			Shares		Amount						Additional paid-in capital			Accumulated deficit				Total shareholders’ equity
Balance at December 31, 2014	274,352		$	270	(578	)	$	(7,615	)	Additional paid-in capital		$	3,502,209			$	(2,984,860	Total shareholders’ equity	)		$	510,004		274,352		$	270		(578	)		$	(7,615	)	$	3,502,209			$	(2,984,860	)		$	510,004
Issuance of common shares	—		—		—		—			98				—				98				5,882		6			—		—				9,875			—				9,881
Equity-based compensation	—		—		—		—			4,743				—				4,743				—		—			—		—				6,439			—				6,439
Restricted shares issued, net of cancellations	(23	)	—		—		—			—				—				—				3,422		—			—		—				—			—				—
Common share dividends	—		—		—		—			—				1				1				—		—			—		—				—			3				3
Treasury share repurchases																						—		—			(17	)	(17		)		—			—				(17		)
Net loss	—		—		—		—			—				(772,267		)		(772,267		)		—		—			—		—				—			(1,126,786		)		(1,126,786		)
Balance at June 30, 2015	274,329		$	270	(578	)	$	(7,615	)	$	3,507,050			$	(3,757,126	)		$	(257,421	)
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	)		283,634		$	276		(595	)	$	(7,632	)		$	3,522,153		$	(4,177,120	)		$	(662,323	)
Issuance of common shares																						243		—			—		—				—			—				—
Equity-based compensation	—		—		—		—			13,594				—				13,594				—		—			—		—				15,240			—				15,240
Restricted shares issued, net of cancellations	(500	)	—		—		—			—				—				—				(837	)	7			—		—				—			—				7
Common share dividends	—		—		—		—			—				20				20				—		—			—		—				—			45				45
Net loss	—		—		—		—			—				(241,495		)		(241,495		)		—		—			—		—				—			(190,559		)		(190,559		)
Balance at June 30, 2016	283,134		$	276	(595	)	$	(7,632	)	$	3,535,747			$	(4,418,595	)		$	(890,204	)
Balance at September 30, 2016																						283,040		$	283		(595	)	$	(7,632	)		$	3,537,393		$	(4,367,634	)		$	(837,590	)

See accompanying notes.

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.

•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 ~~shallow conventional assets and Marcellus shale~~ assets in the Appalachia region ("Appalachia JV"). EXCO and BG Group each own an undivided 50% interest in the Appalachia JV and a 49.75% working interest in the Appalachia JV's properties. The remaining 0.5% working interest is held by a jointly owned operating entity ("OPCO") that operates the Appalachia JV's properties. We own a 50% interest in OPCO. 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.~~well, and on October 3, 2016, we closed the sale of our interests in shallow conventional assets located in West Virginia. See "Note ~~13. Subsequent events"~~3. Divestitures" for additional discussion.

The accompanying Condensed Consolidated Balance Sheets as of ~~June~~September 30, 2016 and December 31, 2015, Condensed Consolidated Statements of Operations for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015 are for EXCO and its subsidiaries. The ~~condensed consolidated financial statements~~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 ~~June~~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 ~~June~~September 30, 2016, ~~we were~~the Company had $3.5 million in ~~compliance with the financial covenants~~cash and cash equivalents, $75.4 million of availability under ~~our~~its credit agreement (“("EXCO Resources Credit ~~Agreement”~~Agreement")~~. However, based on~~ and a working capital deficit of $131.1 million. We have substantial interest payment obligations related to 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 during~~debt over the next twelve months.

As part of our comprehensive restructuring program, on July 27, 2016, we announced a commencement of a cash tender offer for our outstanding senior unsecured notes up to a maximum combined aggregate price paid of $40.0 million ("Tender Offer"). See “Note 13. Subsequent events” for additional information. If we are successful in the Tender Offer, the purchases are expected to be funded primarily with the borrowings under the EXCO Resources Credit Agreement. There can be no assurances regarding the success or extent of the purchases of the senior unsecured notes as part of the Tender Offer process. Furthermore, the The next borrowing base redetermination under the EXCO Resources Credit Agreement is ~~scheduled~~expected to occur ~~on or about September 1,~~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~~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~~Consolidated Current Ratio covenant under the EXCO Resources Credit Agreement. Therefore, the reduction in unused commitments as a result of borrowings ~~to fund~~under the ~~Tender Offer~~EXCO Resources Credit Agreement or further reductions to our borrowing base as part of the ~~upcoming~~ redetermination process ~~would~~will negatively impact our ~~consolidated current ratio~~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 ~~current ratio~~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 ~~expect to maintain~~may not be in compliance with these covenants as early as the ~~minimum requirements for the~~fiscal quarter ending December 31, 2016 depending on our future financial ~~covenants in the EXCO Resources Credit Agreement related to the ratio of consolidated EBITDAX to consolidated interest expense (“Interest Coverage Ratio”)~~and operating results and the ~~ratio~~outcome of ~~senior secured indebtedness~~the borrowing base redetermination process. Furthermore, our liquidity is not expected to ~~consolidated EBITDAX (“Senior Secured Indebtedness Ratio”)~~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 ~~meet~~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.

Our decision to commence the Tender Offer process is part of EXCO’s comprehensive restructuring process focused on improving its capital structure and providing structural liquidity. We are evaluating transactions that could further enhance our liquidity and capital structure including the exchanges of existing indebtedness for common shares, issuance of additional indebtedness, the restructuring or repurchase of existing indebtedness, issuance of equity, restructuring of gathering, transportation and certain other commercial contracts, cost reductions, divestitures of assets or similar transactions. There is no assurance any such transactions will occur.

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

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.

~~Concentration~~Recent accounting pronouncements

In August 2016, the FASB issued Accounting Standards Update ("ASU") No. 2016-15, Statement of ~~credit risk~~

~~We sell oil~~Cash Flows (Topic 230): Classification of Certain Cash Receipts and ~~natural gas~~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 ~~various customers~~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 ~~certain customers account~~distributions received from equity method investees. ASU 2016-15 is effective for ~~a significant amount of our total consolidated revenues. The majority of our accounts receivable are due from either purchasers of oil or natural gas or participants in oil~~annual and ~~natural gas wells for which we serve as the operator. We have the right to offset future revenues against unpaid charges related to wells that we operate.~~interim periods beginning after December 15, 2017. We are ~~managing~~currently assessing the potential impact of ASU 2016-15 on our ~~credit risk as a result~~consolidated financial condition and results of the current commodity price environment through the attainment of financial assurances from certain customers. In 2016, we entered into an agreement with a significant customer to prepay us for estimated future oil and natural gas production. At June 30, 2016, we recorded $26.0 million of prepayments from the customer, which are included in "Accounts payable and accrued liabilities" or in "Revenues and royalties payable" in the Condensed Consolidated Balance Sheets.

~~Recent accounting pronouncements~~operations.

In May 2016, the ~~Financial Accounting Standards Board ("FASB")~~FASB issued ~~Accounting Standards Update ("ASU")~~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.

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 ~~six~~nine months ended ~~June~~September 30, 2016:


(in thousands)
Asset retirement obligations at beginning of period	$	41,648		$	41,648
Activity during the period:
Liabilities settled during the period	(59		)	(59		)
Adjustment to liability due to divestitures(1)	(30		)	(22,859		)
Accretion of discount	1,681			2,006
Asset retirement obligations at end of period	43,240			20,736
Less current portion	845			428
Long-term portion	$	42,395		$	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. See "Note 13. Subsequent events" for further details regarding the impact of the divestiture of conventional assets in July 2016 on our~~ 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 ~~six~~nine months ended ~~June~~September 30, 2016 orand 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				Average spot prices
	Oil (per Bbl)		Natural gas (per Mmbtu)		Oil (per Bbl)		Natural gas (per Mmbtu)
September 30, 2016					$	41.68	$	2.24
June 30, 2016	$	43.12	$	2.24	43.12		2.24
March 31, 2016	46.26		2.40		46.26		2.40
December 31, 2015	50.28		2.59		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 ~~$26.2~~$339.4 million and ~~$160.8 million~~$1.0 billion for the three and ~~six~~nine months ended ~~June 30, 2016, respectively, and $394.3 million and $670.7 million for the three and six months ended June~~September 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. ~~The spot prices on the first day of July 2016 exceeded the trailing twelve-month reference prices at June 30, 2016. However, oil~~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 ~~June~~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. Our liquidity and capital resources continue to be impacted by the current commodity price environment as evidenced by factors such as the reduction to the borrowing base under the EXCO Resources Credit Agreement in March 2016 and other circumstances. As such, these factors resulted in uncertainty regarding the extent and types of financing available for our future development activities. 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.

6.~~Loss~~Earnings (loss) per share

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


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands, except per share data)	2016			2015			2016			2015			2016		2015			2016			2015
Basic net loss per common share:
Net loss	$	(111,347	)	$	(454,155	)	$	(241,495	)	$	(772,267	)
Basic net income (loss) per common share:
Net income (loss)													$	50,936	$	(354,519	)	$	(190,559	)	$	(1,126,786	)
Weighted average common shares outstanding	278,783			271,549			278,570			271,536			279,873		273,348			279,008			272,147
Net loss per basic common share	$	(0.40	)	$	(1.67	)	$	(0.87	)	$	(2.84	)
Diluted net loss per common share:
Net loss	$	(111,347	)	$	(454,155	)	$	(241,495	)	$	(772,267	)
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	278,783			271,549			278,570			271,536			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	278,783			271,549			278,570			271,536			281,045		273,348			279,008			272,147
Net loss per diluted common share	$	(0.40	)	$	(1.67	)	$	(0.87	)	$	(2.84	)
Net income (loss) per diluted common share													$	0.18	$	(1.30	)	$	(0.68	)	$	(4.14	)

Diluted net ~~loss~~income (loss) per common share for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015 is computed in the same manner as basic ~~loss~~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 ~~loss~~net income (loss) per share excluded ~~88,537,824~~88,083,055 and ~~12,152,822~~36,157,630 antidilutive share equivalents for the three months ended ~~June~~September 30, 2016 and 2015, respectively, and ~~89,849,375~~89,522,616 and ~~12,657,675~~21,200,285 antidilutive share equivalents for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, respectively. Our antidilutive share equivalents for the three and ~~six~~nine months ended ~~June~~September 30, 2016 included 80,000,000 warrants issued to Energy Strategic Advisory Services LLC ("ESAS"). See "Note ~~11.~~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.

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)	June 30, 2016			December 31, 2015			September 30, 2016			December 31, 2015
Derivative financial instruments - Current assets	$	8,686		$	39,499		$	5,952		$	39,499
Derivative financial instruments - Long-term assets	1,572			6,109			1,455			6,109
Derivative financial instruments - Current liabilities	(15,559		)	(16		)	(10,353		)	(16		)
Derivative financial instruments - Long-term liabilities	(2,335		)	—			(1,189		)	—
Net derivative financial instruments	$	(7,636	)	$	45,592		$	(4,135	)	$	45,592

Effect of Derivative Financial Instruments


	Three Months Ended June 30,						Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2016			2015			2016			2015		2016		2015		2016			2015
Gain (loss) on derivative financial instruments	$	(36,432	)	$	(6,631	)	$	(19,841	)	$	17,079	$	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 ~~includes~~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 ~~our credit agreement~~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 ~~June~~September 30, 2016:


(dollars in thousands, except prices)	Volume Bbtu/Mbbl	Weighted average strike price per Mmbtu/Bbl		Fair value at June 30, 2016			Volume Bbtu/Mbbl	Weighted average strike price per Mmbtu/Bbl		Fair value at September 30, 2016
Natural gas:
Swaps:
Remainder of 2016	28,520	$	2.88	$	(3,819	)	14,260	$	2.88	$	(1,610	)
2017	23,700	2.99		(4,526		)	23,700	2.99		(2,440		)
2018	3,650	3.15		410			3,650	3.15		819
Swaptions:
2017	7,300	2.76		(3,603		)	7,300	2.76		(2,743		)
Collars:
2017	3,650			(295		)	10,950			(420		)
Sold call		3.43						3.28
Purchased put		2.80						2.87
Total natural gas				$	(11,833	)				$	(6,394	)
Oil:
Swaps:
Remainder of 2016	552	$	58.61	$	4,610		276	$	58.61	$	2,542
2017	183	50.00		(413		)	183	50.00		(283		)
Total oil				$	4,197					$	2,259
Total oil and natural gas derivative financial instruments				$	(7,636	)				$	(4,135	)

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

At ~~June~~September 30, 2016, the average forward NYMEX WTI oil prices per Bbl for the remainder of 2016 and calendar year 2017 were ~~$49.59~~$48.53 and ~~$52.20,~~$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 ~~$3.03, $3.18~~$3.02, $3.09 and ~~$3.02,~~$2.91, respectively.

Our derivative financial instruments covered approximately ~~58%~~60% and ~~65%~~69% of production volumes for the three months ended ~~June~~September 30, 2016 and 2015, respectively, and ~~52%~~55% and ~~65%~~66% of production volumes for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, respectively.

8.Debt

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


(in thousands)	June 30, 2016			December 31, 2015			September 30, 2016			December 31, 2015
EXCO Resources Credit Agreement	$	121,592		$	67,492		$	214,592		$	67,492
Exchange Term Loan	615,894			641,172			603,116			641,172
Fairfax Term Loan	300,000			300,000			300,000			300,000
2018 Notes	131,576			158,015			131,576			158,015
Unamortized discount on 2018 Notes	(656		)	(932		)	(589		)	(932		)
2022 Notes	171,432			222,826			70,169			222,826
Deferred financing costs, net	(15,401		)	(18,294		)	(12,796		)	(18,294		)
Total debt	1,324,437			1,370,279			1,306,068			1,370,279
Less amounts due within one year	50,000			50,000			50,000			50,000
Total debt due after one year	$	1,274,437		$	1,320,279		$	1,256,068		$	1,320,279


	June 30, 2016										September 30, 2016
(in thousands)	Carrying value			Deferred reduction in carrying value			Unamortized discount/deferred financing costs		Principal balance		Carrying value			Deferred reduction in carrying value			Unamortized discount/deferred financing costs		Principal balance
EXCO Resources Credit Agreement	$	121,592		$	—		$	—	$	121,592	$	214,592		$	—		$	—	$	214,592
Exchange Term Loan	615,894			(215,894		)	—		400,000		603,116			(203,116		)	—		400,000
Fairfax Term Loan	300,000			—			—		300,000		300,000			—			—		300,000
2018 Notes	130,920			—			656		131,576		130,987			—			589		131,576
2022 Notes	171,432			—			—		171,432		70,169			—			—		70,169
Deferred financing costs, net	(15,401		)	—			15,401		—		(12,796		)	—			12,796		—
Total debt	$	1,324,437		$	(215,894	)	$	16,057	$	1,124,600	$	1,306,068		$	(203,116	)	$	13,385	$	1,116,337

Terms and conditions of our debt obligations are discussed below.

~~Recent transactions~~

~~In the second quarter of~~Tender Offer and open market repurchases

On August 24, 2016, we completed ~~additional transactions focused on reducing~~a cash tender offer for our ~~indebtedness including open market repurchases~~outstanding senior unsecured notes ("Tender Offer") that resulted in the repurchase of an aggregate of ~~$12.0~~$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 ended September 30, 2016, we repurchased an aggregate of $26.4 million and ~~$11.5~~$152.7 million in principal amount of the 2018 Notes and 2022 Notes, respectively, with an aggregate of ~~$5.4~~$53.3 million in ~~cash. For~~cash through the ~~six months ended June 30, 2016, we repurchased an aggregate of $26.4 million~~Tender Offer and ~~$51.4 million in principal amount of the 2018 Notes and 2022 Notes, respectively, with an aggregate of $13.3 million in cash. The~~ open market repurchases. These repurchases resulted in a net ~~gain~~gains on extinguishment of debt of ~~$16.8~~$57.4 million and ~~$62.0~~$119.4 million for the three and ~~six~~nine months ended ~~June~~September 30, 2016, respectively.

~~On July 27,~~EXCO Resources Credit Agreement

As of September 30, 2016, we ~~announced the commencement~~had $214.6 million of outstanding indebtedness and a ~~Tender Offer for the 2018 Notes and 2022 Notes up to a maximum combined amount~~borrowing base of ~~$40.0~~$325.0 million ~~on the aggregate price paid. We expect to fund these purchases primarily with borrowings~~ under the EXCO Resources Credit Agreement. ~~See “Note 13. Subsequent events” for a more detailed discussion and~~On September 1, 2016, the ~~terms of the Tender Offer.~~

~~EXCO Resources Credit Agreement~~

~~As of June 30, 2016, we had $121.6 million of outstanding indebtedness,~~ ~~$325.0 million~~ ~~of available borrowing base and $193.2 million of unused borrowing base, net of letters of credit~~lenders under the EXCO Resources Credit ~~Agreement.~~ 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 ~~ranged~~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 ~~June~~September 30, 2016, our interest rate was approximately ~~3.0%~~3.5%.

As of ~~June~~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~~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;~~Agreement. As of September 30, 2016, the unused commitments were based on the Company's borrowing base of $325.0 million;

maintain an a ratio of consolidated EBITDAX to consolidated interest expense (“Interest Coverage ~~Ratio~~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 ~~(as defined below)~~ 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,” and together with the Fairfax Term Loan, “Second Lien Term Loans”~~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;~~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 ~~EXCO Resources Credit Agreement~~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 ~~EXCO Resources Credit Agreement~~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 ~~June~~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 ~~June~~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. ~~Additionally, as~~On August 24, 2016, we completed the Tender Offer that resulted in the repurchases of ~~June~~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 ~~$51.4~~$152.7 million in principal amount of the 2022 Notes for an aggregate of ~~$6.5 million in a series of open market repurchases.~~$46.5 million. As a result of the repurchases, the aggregate principal amount of outstanding 2022 Notes was reduced to ~~$171.4~~$70.2 million as of ~~June~~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

"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.

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 ~~six~~nine months ended ~~June~~September 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 ~~June~~September 30, 2016 and December 31, 2015.


	June 30, 2016										September 30, 2016
(in thousands)	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	(7,636	)	$	—	$	(7,636	)	$	—	$	(4,135	)	$	—	$	(4,135	)
	December 31, 2015										December 31, 2015
(in thousands)	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	45,592		$	—	$	45,592		$	—	$	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 ~~swap~~swaps, collars and swaption contracts, is discussed below.

Oil derivatives. Our oil derivatives are swap contracts for notional ~~Bbls~~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.


	June 30, 2016								September 30, 2016
(in thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
2018 Notes	$	48,025	$	—	$	—	$	48,025	$	60,438	$	—	$	—	$	60,438
2022 Notes	51,430		—		—		51,430		27,366		—		—		27,366
Exchange Term Loan	—		173,252		—		173,252		—		263,500		—		263,500
Fairfax Term Loan	—		129,750		—		129,750		—		197,625		—		197,625
	December 31, 2015								December 31, 2015
(in thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
2018 Notes	$	43,170	$	—	$	—	$	43,170	$	43,170	$	—	$	—	$	43,170
2022 Notes	48,376		—		—		48,376		48,376		—		—		48,376
Exchange Term Loan	—		278,000		—		278,000		—		278,000		—		278,000
Fairfax Term Loan	—		208,500		—		208,500		—		208,500		—		208,500

Other fair value measurements

During the ~~six~~nine months ended ~~June~~September 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 ~~13. Subsequent events"~~9. Commitments and contingencies", we recorded a ~~$24.3~~$23.2 million ~~liability in "Accounts payable and accrued liabilities" in our Condensed Consolidated Balance Sheet with a corresponding~~ loss in "Other operating items" in our Condensed Consolidated Statements of Operations ~~as of June~~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 ~~liability was based on our estimated exposure from a potential adverse ruling in the litigation. 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. Upon the finalization of the settlement and transfer of interests on July 25, 2016, the extinguishment of the liability was treated as an adjustment to the capitalized costs of our oil and natural gas properties.

~~10.~~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 ~~$88.5~~$69.4 million for the ~~six~~nine months ended ~~June~~September 30, 2016. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $1.4 billion ~~which~~that have fully offset our net deferred tax assets as of ~~June~~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.

~~11.~~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 ~~six~~nine months ended ~~June~~September 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 ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, these transactions included the following:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2016		2015		2016		2015		2016		2015		2016		2015
Amounts received from OPCO	$	3,643	$	8,273	$	8,762	$	16,566	$	3,824	$	7,281	$	12,586	$	23,847

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


(in thousands)	June 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Amounts due to EXCO (1)	$	1,287	$	1,733	$	932	$	1,733
Amounts due from EXCO (1)	12,616		10,410		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 ~~will pay~~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, provided that~~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 ~~for~~to ESAS of $7.2 million, which consisted of (i) the ~~services will be~~monthly fees previously held in escrow and ~~contingent upon completion~~(ii) a $2.4 million annual incentive payment as a result of EXCO achieving a performance rank above the 75th percentile of the ~~entire first year of services and required investment in EXCO. We accrued a total of $6.9~~peer group. Our accrual totaled $0.9 million and $4.5 million at ~~June~~September 30, 2016 and December 31, 2015, respectively, for the services performed under the services

and investment agreement, and is recorded ~~these amounts~~ in "Accounts payable and accrued liabilities" in our Condensed Consolidated Balance Sheets. The ~~total~~ amount ~~accrued~~ at ~~June~~September 30, 2016 includes an accrual for the ~~entire first year~~ annual incentive payment of $0.6 million as a result of EXCO's performance ~~rank above the 75th percentile of the peer group, which is expected to be paid to ESAS in the fourth quarter of 2016.~~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 ~~six~~nine months ended ~~June~~September 30, 2016, we recognized equity-based compensation related to the warrants of ~~$8.9~~$0.9 million and ~~$10.9~~$11.8 million, ~~respectively.~~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 ~~June~~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’~~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 ~~June~~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.

~~12.~~13.Condensed consolidating financial statements

As of ~~June~~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)

~~June~~September 30, 2016


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated			Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	36,623		$	(9,060	)	$	—	$	—		$	27,563		$	9,754		$	(6,220	)	$	—	$	—		$	3,534
Restricted cash	4,201			21,284			—		—			25,485			—			18,434			—		—			18,434
Other current assets	15,303			26,937			—		—			42,240			13,233			75,608			—		—			88,841
Total current assets	56,127			39,161			—		—			95,288			22,987			87,822			—		—			110,809
Equity investments	—			—			32,796		—			32,796			—			—			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	—			96,147			—		—			96,147			—			93,511			—		—			93,511
Proved developed and undeveloped oil and natural gas properties	330,777			2,644,651			—		—			2,975,428			331,326			2,615,315			—		—			2,946,641
Accumulated depletion	(330,777		)	(2,344,306		)	—		—			(2,675,083		)	(330,776		)	(2,359,835		)	—		—			(2,690,611		)
Oil and natural gas properties, net	—			396,492			—		—			396,492			550			348,991			—		—			349,541
Other property and equipment, net	642			24,600			—		—			25,242			608			23,450			—		—			24,058
Investments in and advances to affiliates, net	396,168			—			—		(396,168		)	—			452,896			—			—		(452,896		)	—
Deferred financing costs, net	5,891			—			—		—			5,891			5,000			—			—		—			5,000
Derivative financial instruments	1,572			—			—		—			1,572			1,455			—			—		—			1,455
Goodwill	13,293			149,862			—		—			163,155			13,293			149,862			—		—			163,155
Total assets	$	473,693		$	610,115		$	32,796	$	(396,168	)	$	720,436		$	496,789		$	610,125		$	31,973	$	(452,896	)	$	685,991
Liabilities and shareholders' equity
Current liabilities	$	85,715		$	202,539		$	—	$	—		$	288,254		$	74,818		$	167,105		$	—	$	—		$	241,923
Long-term debt	1,274,437			—			—		—			1,274,437			1,256,068			—			—		—			1,256,068
Other long-term liabilities	3,745			44,204			—		—			47,949			3,493			22,097			—		—			25,590
Payable to parent	—			2,302,520			—		(2,302,520		)	—			—			2,360,227			—		(2,360,227		)	—
Total shareholders' equity	(890,204		)	(1,939,148		)	32,796		1,906,352			(890,204		)	(837,590		)	(1,939,304		)	31,973		1,907,331			(837,590		)
Total liabilities and shareholders' equity	$	473,693		$	610,115		$	32,796	$	(396,168	)	$	720,436		$	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 ended ~~June~~September 30, 2016


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated			Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	54,221		$	—		$	—	$	54,221		$	—		$	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	3			12,414			—			—		12,417			—			12,608			—			—		12,608
Gathering and transportation	—			26,895			—			—		26,895			—			27,979			—			—		27,979
Purchased natural gas															—			6,586			—			—		6,586
Depletion, depreciation and amortization	90			18,994			—			—		19,084			89			15,821			—			—		15,910
Impairment of oil and natural gas properties	291			25,923			—			—		26,214			—			—			—			—		—
Accretion of discount on asset retirement obligations	—			769			—			—		769			—			325			—			—		325
General and administrative	2,300			14,683			—			—		16,983			(4,395		)	15,141			—			—		10,746
Other operating items	—			24,856			—			—		24,856			—			(1,110		)	—			—		(1,110		)
Total costs and expenses	2,684			124,534			—			—		127,218			(4,306		)	77,350			—			—		73,044
Operating loss	(2,684		)	(70,313		)	—			—		(72,997		)
Operating income (loss)															4,306			(164		)	—			—		4,142
Other income (expense):
Interest expense, net	(17,932		)	—			—			—		(17,932		)	(16,997		)	—			—					(16,997		)
Loss on derivative financial instruments	(36,432		)	—			—			—		(36,432		)
Gain on derivative financial instruments															8,209			—			—					8,209
Gain on extinguishment of debt	16,839											16,839			57,421			—			—					57,421
Other income	4			9			—			—		13			4			8			—					12
Equity loss	—			—			(91		)	—		(91		)	—			—			(823		)			(823		)
Net loss from consolidated subsidiaries	(70,395		)	—			—			70,395		—			(979		)	—			—			979		—
Total other income (expense)	(107,916		)	9			(91		)	70,395		(37,603		)	47,658			8			(823		)	979		47,822
Loss before income taxes	(110,600		)	(70,304		)	(91		)	70,395		(110,600		)
Income (loss) before income taxes															51,964			(156		)	(823		)	979		51,964
Income tax expense	747			—			—			—		747			1,028			—			—			—		1,028
Net loss	$	(111,347	)	$	(70,304	)	$	(91	)	$	70,395	$	(111,347	)
Net income (loss)															$	50,936		$	(156	)	$	(823	)	$	979	$	50,936

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended ~~June~~September 30, 2015


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated			Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	(18	)	$	93,760		$	—		$	—	$	93,742		$	—		$	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	(15		)	19,753			—			—		19,738			7			18,606			—			—		18,613
Gathering and transportation				24,785			—			—		24,785			—			23,743			—			—		23,743
Purchased natural gas															—			6,991			—			—		6,991
Depletion, depreciation and amortization	245			61,413			—			—		61,658			229			51,784			—			—		52,013
Impairment of oil and natural gas properties	1,551			392,776			—			—		394,327			1,372			338,021			—			—		339,393
Accretion of discount on asset retirement obligations	—			568			—			—		568			—			574			—			—		574
General and administrative	(3,503		)	16,100			—			—		12,597			(2,345		)	15,738			—			—		13,393
Other operating items	1,916			(382		)	—			—		1,534			(3		)	(225		)	—			—		(228		)
Total costs and expenses	194			515,013			—			—		515,207			(740		)	455,232			—			—		454,492
Operating loss	(212		)	(421,253		)	—			—		(421,465		)
Operating income (loss)															740			(364,715		)	—			—		(363,975		)
Other income (expense):
Interest expense, net	(25,571		)	—			—			—		(25,571		)	(27,761		)	—			—			—		(27,761		)
Loss on derivative financial instruments	(6,631		)	—			—			—		(6,631		)
Gain on derivative financial instruments															37,348			—			—			—		37,348
Other income	39			8			—			—		47			14			7			—			—		21
Equity loss	—			—			(535		)	—		(535		)	—			—			(152		)	—		(152		)
Net loss from consolidated subsidiaries	(421,780		)	—			—			421,780		—			(364,860		)	—			—			364,860		—
Total other income (expense)	(453,943		)	8			(535		)	421,780		(32,690		)	(355,259		)	7			(152		)	364,860		9,456
Loss before income taxes	(454,155		)	(421,245		)	(535		)	421,780		(454,155		)	(354,519		)	(364,708		)	(152		)	364,860		(354,519		)
Income tax expense	—			—			—			—		—			—			—			—			—		—
Net loss	$	(454,155	)	$	(421,245	)	$	(535	)	$	421,780	$	(454,155	)	$	(354,519	)	$	(364,708	)	$	(152	)	$	364,860	$	(354,519	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the ~~six~~nine months ended ~~June~~September 30, 2016


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated			Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	105,870		$	—		$	—	$	105,870		$	—		$	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	5			26,530			—			—		26,535			4			39,139			—			—		39,143
Gathering and transportation	—			53,525			—			—		53,525			—			79,828			—			—		79,828
Purchased natural gas															—			17,273			—			—		17,273
Depletion, depreciation and amortization	209			47,876			—			—		48,085			298			63,697			—			—		63,995
Impairment of oil and natural gas properties	838			159,975			—			—		160,813			838			159,975			—			—		160,813
Accretion of discount on asset retirement obligations	—			1,681			—			—		1,681			—			2,006			—			—		2,006
General and administrative	(1,666		)	29,546			—			—		27,880			(6,062		)	44,688			—			—		38,626
Other operating items	(407		)	25,453			—			—		25,046			(406		)	24,342			—			—		23,936
Total costs and expenses	(1,021		)	344,586			—			—		343,565			(5,328		)	430,948			—			—		425,620
Operating income (loss)	1,021			(238,716		)	—			—		(237,695		)	5,328			(238,881		)	—			—		(233,553		)
Other income (expense):
Interest expense, net	(37,189		)	—			—			—		(37,189		)	(54,186		)	—			—			—		(54,186		)
Loss on derivative financial instruments	(19,841		)	—			—			—		(19,841		)	(11,632		)	—			—			—		(11,632		)
Gain on extinguishment of debt	61,953			—			—			—		61,953			119,374			—			—			—		119,374
Other income	6			19			—			—		25			9			28			—			—		37
Equity loss	—			—			(8,001		)	—		(8,001		)	—			—			(8,824		)	—		(8,824		)
Net loss from consolidated subsidiaries	(246,698		)	—			—			246,698		—			(247,677		)	—			—			247,677		—
Total other income (expense)	(241,769		)	19			(8,001		)	246,698		(3,053		)	(194,112		)	28			(8,824		)	247,677		44,769
Loss before income taxes	(240,748		)	(238,697		)	(8,001		)	246,698		(240,748		)	(188,784		)	(238,853		)	(8,824		)	247,677		(188,784		)
Income tax expense	747			—			—			—		747			1,775			—			—			—		1,775
Net loss	$	(241,495	)	$	(238,697	)	$	(8,001	)	$	246,698	$	(241,495	)	$	(190,559	)	$	(238,853	)	$	(8,824	)	$	247,677	$	(190,559	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the ~~six~~nine months ended ~~June~~September 30, 2015


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated			Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	4		$	180,058		$	—		$	—	$	180,062		$	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	23			39,517			—			—		39,540			30			58,123			—			—		58,153
Gathering and transportation	—			50,500			—			—		50,500			—			74,243			—			—		74,243
Purchased natural gas															—			21,571			—			—		21,571
Depletion, depreciation and amortization	524			123,623			—			—		124,147			753			175,407			—			—		176,160
Impairment of oil and natural gas properties	6,891			663,763			—			—		670,654			8,263			1,001,784			—			—		1,010,047
Accretion of discount on asset retirement obligations	4			1,120			—			—		1,124			4			1,694			—			—		1,698
General and administrative	(4,224		)	32,058			—			—		27,834			(6,569		)	47,796			—			—		41,227
Other operating items	2,068			(722		)	—			—		1,346			2,065			(947		)	—			—		1,118
Total costs and expenses	5,286			909,859			—			—		915,145			4,546			1,379,671			—			—		1,384,217
Operating loss	(5,282		)	(729,801		)	—			—		(735,083		)	(4,542		)	(1,094,516		)	—			—		(1,099,058		)
Other income (expense):
Interest expense, net	(53,061		)	—			—			—		(53,061		)	(80,822		)	—			—			—		(80,822		)
Gain on derivative financial instruments	17,079			—			—			—		17,079			54,427			—			—			—		54,427
Other income	73			25			—			—		98			87			32			—			—		119
Equity loss	—			—			(1,300		)	—		(1,300		)	—			—			(1,452		)	—		(1,452		)
Net loss from consolidated subsidiaries	(731,076		)	—			—			731,076		—			(1,095,936		)	—			—			1,095,936		—
Total other income (expense)	(766,985		)	25			(1,300		)	731,076		(37,184		)	(1,122,244		)	32			(1,452		)	1,095,936		(27,728		)
Loss before income taxes	(772,267		)	(729,776		)	(1,300		)	731,076		(772,267		)	(1,126,786		)	(1,094,484		)	(1,452		)	1,095,936		(1,126,786		)
Income tax expense	—			—			—			—		—			—			—			—			—		—
Net loss	$	(772,267	)	$	(729,776	)	$	(1,300	)	$	731,076	$	(772,267	)	$	(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 ~~six~~nine months ended ~~June~~September 30, 2016


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated			Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	16,452		$	29,473		$	—	$	—	$	45,925
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	(833		)	(54,130		)			—		(54,963		)	(1,250		)	(69,205		)	—		—		(70,455		)
Proceeds from disposition of property and equipment	10			11,480			—		—		11,490			10			11,232			—		—		11,242
Restricted cash	—			(2,164		)	—		—		(2,164		)	—			686			—		—		686
Net changes in advances to joint ventures	—			2,404			—		—		2,404			—			2,377			—		—		2,377
Equity investments and other	—			—			—		—		—			—			—			—		—		—
Advances/investments with affiliates	(25,926		)	25,926			—		—		—			(83,631		)	83,631			—		—		—
Net cash used in investing activities	(26,749		)	(16,484		)	—		—		(43,233		)
Net cash provided by (used in) investing activities														(84,871		)	28,721			—		—		(56,150		)
Financing Activities:
Borrowings under EXCO Resources Credit Agreement	297,897			—			—		—		297,897			390,897			—			—		—		390,897
Repayments under EXCO Resources Credit Agreement	(243,797		)	—			—		—		(243,797		)	(243,797		)	—			—		—		(243,797		)
Payments on Exchange Term Loan	(25,278		)	—			—		—		(25,278		)	(38,056		)	—			—		—		(38,056		)
Repurchases of senior unsecured notes	(13,299		)	—			—		—		(13,299		)	(53,298		)	—			—		—		(53,298		)
Deferred financing costs and other	(2,899		)	—			—		—		(2,899		)	(4,569		)	—			—		—		(4,569		)
Net cash provided by financing activities	12,624			—			—		—		12,624			51,177			—			—		—		51,177
Net increase in cash	2,327			12,989			—		—		15,316
Net increase (decrease) in cash														(24,542		)	15,829			—		—		(8,713		)
Cash at beginning of period	34,296			(22,049		)	—		—		12,247			34,296			(22,049		)	—		—		12,247
Cash at end of period	$	36,623		$	(9,060	)	$	—	$	—	$	27,563		$	9,754		$	(6,220	)	$	—	$	—	$	3,534

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the ~~six~~nine months ended ~~June~~September 30, 2015


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated			Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	19,024		$	89,180		$	—	$	—	$	108,204		$	27,860		$	98,996		$	—	$	—	$	126,856
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(1,174		)	(211,034		)	—		—		(212,208		)	(1,784		)	(275,532		)	—		—		(277,316		)
Proceeds from disposition of property and equipment	686			6,711			—		—		7,397			686			6,711			—		—		7,397
Restricted cash	—			6,989			—		—		6,989			—			4,016			—		—		4,016
Net changes in advances to joint ventures	—			5,756			—		—		5,756			—			8,594			—		—		8,594
Equity investments and other	—			(503		)	—		—		(503		)	—			1,455			—		—		1,455
Advances/investments with affiliates	(124,371		)	124,371			—		—		—			(181,813		)	181,813			—		—		—
Net cash used in investing activities	(124,859		)	(67,710		)	—		—		(192,569		)	(182,911		)	(72,943		)	—		—		(255,854		)
Financing Activities:
Borrowings under EXCO Resources Credit Agreement	90,000			—			—		—		90,000			97,500			—			—		—		97,500
Repayments under EXCO Resources Credit Agreement	—			—			—		—		—
Proceeds from issuance of common shares, net														9,829			—			—		—		9,829
Deferred financing costs and other	(2,033		)	—			—		—		(2,033		)	(4,125		)	—			—		—		(4,125		)
Net cash provided by financing activities	87,967			—			—		—		87,967			103,204			—			—		—		103,204
Net increase (decrease) in cash	(17,868		)	21,470			—		—		3,602			(51,847		)	26,053			—		—		(25,794		)
Cash at beginning of period	86,837			(40,532		)	—		—		46,305			86,837			(40,532		)	—		—		46,305
Cash at end of period	$	68,969		$	(19,062	)	$	—	$	—	$	49,907		$	34,990		$	(14,479	)	$	—	$	—	$	20,511

~~13.Subsequent events~~

~~Conventional asset divestiture~~

On July 1, 2016, we closed the sale of our interests in shallow conventional assets located in Pennsylvania for approximately $0.1 million, subject to customary post-closing purchase price adjustments, and retained an overriding royalty interest in each well. 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 as of June 30, 2016. In conjunction with the divestiture, the Company reduced its field employee count in the Appalachia region by 52%.

~~Settlement of Participation Agreement litigation~~

On July 25, 2016, we settled the litigation with our joint venture partner, and the litigation was thereafter dismissed by the court entering a final judgment order 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 liability in "Accounts payable and accrued liabilities" in our Condensed Consolidated Balance Sheet with a corresponding loss in "Other operating items" in the Condensed Consolidated Statements of Operations as of June 30, 2016 based on our estimated exposure from a potential adverse ruling in the litigation. The fair value of the Transferred Interests was $24.3 million as of June 30, 2016 based on a discounted cash flow model of the estimated reserves using NYMEX forward strip prices. See "Note 9. Fair value measurements" for additional information. The net production from the Transferred Interests was approximately 350 Bbls of oil per day during June 2016.

~~Tender Offer~~

~~On July 27, 2016, we announced the commencement of a Tender Offer for the 2018 Notes and 2022 Notes up to a maximum combined aggregate price paid of~~ ~~$40.0 million~~. In conjunction with the Tender Offer, we are soliciting consents from registered holders of the 2022 Notes to amend certain terms of the indenture governing the 2022 Notes. The Tender Offer expires on August 23, 2016; however, tendering on or before August 9, 2016, will result in additional consideration received, as follows:

Per $1,000 principal amount of the 2018 Notes that are accepted for purchase, total consideration includes the tender offer consideration of $455.00 and an early tender payment of $45.00, if applicable, for a total consideration of up to $500.00.

Per $1,000 principal amount of the 2022 Notes that are accepted for purchase, total consideration includes the tender offer consideration of $350.00, a consent payment of $5.00, if applicable, and an early tender payment of $45.00, if applicable, for a total consideration of up to $400.00.

Holders of 2018 Notes or 2022 Notes whose notes are accepted for payment in the Tender Offer will receive accumulated and unpaid interest. The purchases are expected to be funded primarily with the borrowings under the EXCO Resources Credit Agreement. For additional information on the Tender Offer, see the Form 8-K filed with the SEC on July 28, 2016.

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

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;

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; ~~and~~

our ability to execute our business strategies and other corporate actions, including restructuring our balance sheet and gathering and transportation ~~contracts.~~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 ~~the~~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 ~~July 27,~~August 24, 2016, we ~~announced the commencement of~~completed a cash tender offer for our outstanding ~~7.5%~~ senior unsecured notes ~~due September 15, 2018~~ ("~~2018 Notes"~~Tender Offer") ~~and~~which resulted in the repurchase of an aggregate of $101.3 million in principal amount of our 8.5% senior unsecured notes due April

15, 2022 ("2022 Notes") ~~up to a maximum combined~~for an aggregate purchase price ~~paid~~ of $40.0 ~~million ("Tender Offer").~~million. See "Note ~~13. Subsequent events"~~8. Debt" in the Notes to our Condensed Consolidated Financial Statements for a more detailed discussion ~~and the terms~~ of the Tender Offer.

~~Note repurchases~~

~~We completed transactions focused on reducing our indebtedness, including~~ During the nine months ended September 30, 2016, through the Tender Offer and a series of open market ~~repurchases of~~purchases, we repurchased an aggregate of ~~$12.0~~$26.4 million and ~~$11.5~~$152.7 million in principal amount of our 7.5% senior unsecured notes due September 15, 2018 ~~Notes~~("2018 Notes") and 2022 Notes, respectively, with an aggregate of $5.4 million in cash during the three months ended June 30, 2016. For the six months ended June 30, 2016, we repurchased an aggregate of $26.4 million and $51.4 million in principal amount of the 2018 Notes and 2022 Notes, respectively, with an aggregate of $13.3$53.3 million in cash. ~~The open market~~These repurchases resulted in net gains on extinguishment of debt of ~~$16.8~~$57.4 million and ~~$62.0~~$119.4 million for the three and ~~six~~nine months ended ~~June~~September 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

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 ~~13. Subsequent events"~~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 ~~for~~and received an overriding royalty interest in each well and approximately $0.1 million, subject to customary post-closing purchase price ~~adjustments~~adjustments. For the six months ended June 30, 2016, the divested assets produced approximately 6 Mmcfe per day and ~~retained an overriding royalty interest in each well. See "Note 13. Subsequent events" in~~ the ~~Notes~~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 ~~our Condensed Consolidated Financial Statements for additional information.~~the divested wells were $22.6 million on July 1, 2016.

See "Note 3. Divestitures" in the ~~sale were used~~Notes to ~~reduce indebtedness under~~ our ~~credit agreement ("EXCO Resources Credit Agreement").~~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. ~~The next scheduled borrowing base redetermination for~~On September 1, 2016, the lenders under the EXCO Resources Credit Agreement ~~is set to occur on or about~~postponed the scheduled redetermination of the borrowing base from September 1, ~~2016.~~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.

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 ~~six~~nine months ended ~~June~~September 30, 2016 and 2015 related to our results of operations is presented below:


	Three Months Ended June 30,						Quarter to quarter change				Six Months Ended June 30,							Period to period change				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				Period to period change			2016			2015				Quarter to quarter change			2016				2015				Period to period change
Production:							Quarter to quarter change
Oil (Mbbls)	447			594			(147		)		997				1,098			(101		)		391			635			(244		)		1,388				1,733			(345		)
Natural gas (Mmcf)	24,284			29,310			(5,026		)		47,819				56,764			(8,945		)		24,107			27,493			(3,386		)		71,926				84,257			(12,331		)
Total production (Mmcfe) (1)	26,966			32,874			(5,908		)		53,801				63,352			(9,551		)		26,453			31,303			(4,850		)		80,254				94,655			(14,401		)
Average daily production (Mmcfe)	296			361			(65		)		296				350			(54		)		288			340			(52		)		293				347			(54		)
Revenues before derivative financial instrument activities:
Oil	$	17,990		$	31,545		$	(13,555	)		$	33,473			$	52,428		$	(18,955	)		$	16,215		$	27,444		$	(11,229	)		$	49,688			$	79,872		$	(30,184	)
Natural gas	36,231			62,197			(25,966		)		72,397				127,634			(55,237		)		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	$	54,221		$	93,742		$	(39,521	)		$	105,870			$	180,062		$	(74,192	)		$	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	$	(36,432	)	$	(6,631	)	$	(29,801	)		$	(19,841	)		$	17,079		$	(36,920	)		$	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)	$	40.25		$	53.11		$	(12.86	)		$	33.57			$	47.75		$	(14.18	)		$	41.47		$	43.22		$	(1.75	)		$	35.80			$	46.09		$	(10.29	)
Natural gas (per Mcf)	1.49			2.12			(0.63		)		1.51				2.25			(0.74		)		2.27			2.05			0.22				1.77				2.19			(0.42		)
Natural gas equivalent (per Mcfe)	2.01			2.85			(0.84		)		1.97				2.84			(0.87		)		2.68			2.68			—				2.20				2.79			(0.59		)
Costs and expenses:
Oil and natural gas operating costs	$	7,560		$	14,135		$	(6,575	)		$	17,038			$	29,076		$	(12,038	)		$	8,797		$	12,669		$	(3,872	)		$	25,835			$	41,745		$	(15,910	)
Production and ad valorem taxes	4,857			5,603			(746		)		9,497				10,464			(967		)		3,811			5,944			(2,133		)		13,308				16,408			(3,100		)
Gathering and transportation	26,895			24,785			2,110				53,525				50,500			3,025				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	18,714			61,115			(42,401		)		47,320				123,015			(75,695		)		15,528			51,494			(35,966		)		62,848				174,509			(111,661		)
Depreciation and amortization	370			543			(173		)		765				1,132			(367		)		382			519			(137		)		1,147				1,651			(504		)
General and administrative (2)	16,983			12,597			4,386				27,880				27,834			46				10,746			13,393			(2,647		)		38,626				41,227			(2,601		)
Interest expense, net	17,932			25,571			(7,639		)		37,189				53,061			(15,872		)		16,997			27,761			(10,764		)		54,186				80,822			(26,636		)
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.28		$	0.43		$	(0.15	)		$	0.32			$	0.46		$	(0.14	)		$	0.33		$	0.40		$	(0.07	)		$	0.32			$	0.44		$	(0.12	)
Production and ad valorem taxes	0.18			0.17			0.01				0.18				0.17			0.01				0.14			0.19			(0.05		)		0.17				0.17			—
Gathering and transportation	1.00			0.75			0.25				0.99				0.80			0.19				1.06			0.76			0.30				0.99				0.78			0.21
Depletion	0.69			1.86			(1.17		)		0.88				1.94			(1.06		)		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		)		0.01			0.02			(0.01		)		0.01				0.02			(0.01		)
Net loss (3)	$	(111,347	)	$	(454,155	)	$	342,808			$	(241,495	)		$	(772,267	)	$	530,772
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 ~~$9.3~~$1.4 million and ~~$1.4~~$0.9 million for the three months ended ~~June~~September 30, 2016 and 2015, respectively, and ~~$13.1~~$14.6 million and ~~$3.1~~$4.0 million for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, respectively.

(3)

Net ~~losses~~loss for the three months ended ~~June~~September 30, ~~2016 and~~ 2015 included ~~$26.2 million and $394.3~~$339.4 million of impairments of oil and natural gas ~~properties, respectively.~~properties. Net losses for the ~~six month~~nine months ended ~~June~~September 30, 2016 and 2015 included $160.8 million and ~~$670.7 million~~$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 ~~six~~nine months ended ~~June~~September 30, 2016 and 2015. The comparability of our results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015 was affected by:

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

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

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 ~~horizontal~~ drilling ~~activities in certain shale formations;~~activities;

significant changes in our capital structure as a result of transactions in 2016 and ~~2015;~~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 ~~six~~nine months ended ~~June~~September 30, 2016 and 2015:


	Three Months Ended June 30,																		Three Months Ended September 30,
	2016					2015					Quarter to quarter change								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			Production (Mmcfe)	Revenue		$/Mcfe		Production (Mmcfe)	Revenue		$/Mcfe		Production (Mmcfe)		Revenue			$/Mcfe
Producing region:
North Louisiana	13,247	$	19,122	$	1.44	21,049	$	47,391	$	2.25	(7,802	)	$	(28,269	)	$	(0.81	)	14,633	$	34,856	$	2.38	18,161	$	39,349	$	2.17	(3,528	)	$	(4,493	)	$	0.21
East Texas	6,877	12,525		1.82		3,664	9,269		2.53		3,213		3,256			(0.71		)	6,312	16,424		2.60		4,763	12,516		2.63		1,549		3,908			(0.03		)
South Texas	2,932	16,675		5.69		3,874	30,082		7.77		(942	)	(13,407		)	(2.08		)	2,517	14,953		5.94		4,064	25,450		6.26		(1,547	)	(10,497		)	(0.32		)
Appalachia and other	3,910	5,899		1.51		4,287	7,000		1.63		(377	)	(1,101		)	(0.12		)	2,991	4,629		1.55		4,315	6,429		1.49		(1,324	)	(1,800		)	0.06
Total	26,966	$	54,221	$	2.01	32,874	$	93,742	$	2.85	(5,908	)	$	(39,521	)	$	(0.84	)	26,453	$	70,862	$	2.68	31,303	$	83,744	$	2.68	(4,850	)	$	(12,882	)	$	—


	Six Months Ended June 30,																		Nine Months Ended September 30,
	2016					2015					Period to period change								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			Production (Mmcfe)	Revenue		$/Mcfe		Production (Mmcfe)	Revenue		$/Mcfe		Production (Mmcfe)		Revenue			$/Mcfe
Producing region:
North Louisiana	27,006	$	41,188	$	1.53	39,690	$	94,061	$	2.37	(12,684	)	$	(52,873	)	$	(0.84	)	41,639	$	76,044	$	1.83	57,851	$	133,751	$	2.31	(16,212	)	$	(57,707	)	$	(0.48	)
East Texas	12,621	23,183		1.84		7,702	21,087		2.74		4,919		2,096			(0.90		)	18,933	39,607		2.09		12,465	33,603		2.70		6,468		6,004			(0.61		)
South Texas	6,486	30,589		4.72		7,119	49,632		6.97		(633	)	(19,043		)	(2.25		)	9,003	45,542		5.06		11,183	75,082		6.71		(2,180	)	(29,540		)	(1.65		)
Appalachia and other	7,688	10,910		1.42		8,841	15,282		1.73		(1,153	)	(4,372		)	(0.31		)	10,679	15,539		1.46		13,156	21,711		1.65		(2,477	)	(6,172		)	(0.19		)
Total	53,801	$	105,870	$	1.97	63,352	$	180,062	$	2.84	(9,551	)	$	(74,192	)	$	(0.87	)	80,254	$	176,732	$	2.20	94,655	$	264,147	$	2.79	(14,401	)	$	(87,415	)	$	(0.59	)

Production for the three and ~~six~~nine months ended ~~June~~September 30, 2016 decreased by ~~5.9~~4.9 Bcfe, or ~~18%~~15%, and ~~9.6~~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 ~~7.8~~3.5 Bcfe and ~~12.7~~16.2 Bcfe for the three and ~~six~~nine months ended ~~June~~September 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 ~~quarter~~and third quarters of 2016.

increased production of ~~3.2~~1.5 Bcfe and ~~4.9~~6.5 Bcfe for the three and ~~six~~nine months ended ~~June~~September 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 ~~0.9~~1.5 Bcfe and ~~0.6~~2.2 Bcfe for the three and ~~six~~nine months ended ~~June~~September 30, 2016, respectively, primarily due to production ~~declines.~~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 ~~0.4~~1.3 Bcfe and ~~1.2~~2.5 Bcfe for the three and ~~six~~nine months ended ~~June~~September 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 ~~0.7~~0.8 Bcfe of production due to low regional natural gas prices during the ~~six~~nine months ended ~~June~~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 ~~13. Subsequent events"~~3. Divestitures" in the Notes to our Condensed Consolidated Financial Statements, on ~~July 1,~~October 3, 2016, we closed a sale of our interests in shallow conventional assets located in ~~Pennsylvania.~~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 ended ~~June~~September 30, 2016 decreased by ~~$39.5~~$12.9 million, or ~~42%~~15%, 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~~production partially offset by an increase in natural gas ~~production.~~prices. The reduction in our development activities and suspension of drilling in certain regions will cause our production to continue to decline ~~in the future~~ unless we increase our development program. Our average natural gas sales price ~~decreased 30%~~increased 11% to ~~$1.49~~$2.27 per Mcf for the three months ended ~~June~~September 30, 2016 from ~~$2.12~~$2.05 per Mcf for the three months ended ~~June~~September 30, 2015, primarily due to ~~lower market prices.~~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 decreased ~~24%~~4% to ~~$40.25~~$41.47 per Bbl for the three months ended ~~June~~September 30, 2016 from ~~$53.11~~$43.22 per Bbl for the three months ended ~~June~~September 30, 2015, primarily due to lower market prices. ~~In July 2016, we renegotiated a sales contract that is expected to improve our realized oil price in future periods.~~

Oil and natural gas revenues for the ~~six~~nine months ended ~~June~~September 30, 2016 decreased by ~~$74.2~~$87.4 million, or ~~41%~~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 decreased ~~33%~~19% to ~~$1.51~~$1.77 per Mcf for the ~~six~~nine months ended ~~June~~September 30, 2016 from ~~$2.25~~$2.19 per Mcf for the ~~six~~nine months ended ~~June~~September 30, 2015, primarily due to lower market prices. Our average sales price of oil per Bbl decreased ~~30%~~22% to ~~$33.57~~$35.80 per Bbl for the ~~six~~nine months ended ~~June~~September 30, 2016 from ~~$47.75~~$46.09 per Bbl for the ~~six~~nine months ended ~~June~~September 30, 2015, primarily due to lower market prices.

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.

Oil and natural gas operating costs

The following tables present our operating costs for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015:


	Three Months Ended June 30,																					Three Months Ended September 30,
	2016						2015						Quarter to quarter change									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			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	$	2,670	$	111	$	2,781	$	3,224	$	1,022	$	4,246	$	(554	)	$	(911	)	$	(1,465	)	$	2,841	$	341	$	3,182	$	3,386	$	252	$	3,638	$	(545	)	$	89		$	(456	)
East Texas	1,108		60		1,168		936		683		1,619		172			(623		)	(451		)	1,482		23		1,505		967		238		1,205		515			(215		)	300
South Texas	2,011		58		2,069		4,555		772		5,327		(2,544		)	(714		)	(3,258		)	2,937		—		2,937		3,814		944		4,758		(877		)	(944		)	(1,821		)
Appalachia and other	1,542		—		1,542		2,818		125		2,943		(1,276		)	(125		)	(1,401		)	1,131		42		1,173		2,753		315		3,068		(1,622		)	(273		)	(1,895		)
Total	$	7,331	$	229	$	7,560	$	11,533	$	2,602	$	14,135	$	(4,202	)	$	(2,373	)	$	(6,575	)	$	8,391	$	406	$	8,797	$	10,920	$	1,749	$	12,669	$	(2,529	)	$	(1,343	)	$	(3,872	)

	Three Months Ended June 30,																					Three Months Ended September 30,
	2016						2015						Quarter to quarter change									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			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	$	0.15	$	0.05	$	0.20	$	0.05		$	(0.04	)	$	0.01		$	0.19	$	0.02	$	0.21	$	0.19	$	0.01	$	0.20	$	—		$	0.01		$	0.01
East Texas	0.16		0.01		0.17		0.26		0.19		0.45		(0.10		)	(0.18		)	(0.28		)	0.23		—		0.23		0.20		0.05		0.25		0.03			(0.05		)	(0.02		)
South Texas	0.69		0.02		0.71		1.18		0.20		1.38		(0.49		)	(0.18		)	(0.67		)	1.17		—		1.17		0.94		0.23		1.17		0.23			(0.23		)	—
Appalachia and other	0.39		—		0.39		0.66		0.03		0.69		(0.27		)	(0.03		)	(0.30		)	0.38		0.01		0.39		0.64		0.07		0.71		(0.26		)	(0.06		)	(0.32		)
Total	$	0.27	$	0.01	$	0.28	$	0.35	$	0.08	$	0.43	$	(0.08	)	$	(0.07	)	$	(0.15	)	$	0.32	$	0.01	$	0.33	$	0.35	$	0.05	$	0.40	$	(0.03	)	$	(0.04	)	$	(0.07	)


	Six Months Ended June 30,																					Nine Months Ended September 30,
	2016						2015						Period to period change									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			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	$	5,580	$	152	$	5,732	$	6,428	$	2,385	$	8,813	$	(848	)	$	(2,233	)	$	(3,081	)	$	8,421	$	493	$	8,914	$	9,814	$	2,637	$	12,451	$	(1,393	)	$	(2,144	)	$	(3,537	)
East Texas	2,264		206		2,470		2,016		789		2,805		248			(583		)	(335		)	3,746		229		3,975		2,983		1,027		4,010		763			(798		)	(35		)
South Texas	5,569		246		5,815		10,833		812		11,645		(5,264		)	(566		)	(5,830		)	8,506		246		8,752		14,647		1,756		16,403		(6,141		)	(1,510		)	(7,651		)
Appalachia and other	3,021		—		3,021		5,688		125		5,813		(2,667		)	(125		)	(2,792		)	4,152		42		4,194		8,441		440		8,881		(4,289		)	(398		)	(4,687		)
Total	$	16,434	$	604	$	17,038	$	24,965	$	4,111	$	29,076	$	(8,531	)	$	(3,507	)	$	(12,038	)	$	24,825	$	1,010	$	25,835	$	35,885	$	5,860	$	41,745	$	(11,060	)	$	(4,850	)	$	(15,910	)

	Six Months Ended June 30,																					Nine Months Ended September 30,
	2016						2015						Period to period change									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			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	$	0.21	$	0.01	$	0.22	$	0.16	$	0.06	$	0.22	$	0.05		$	(0.05	)	$	—		$	0.20	$	0.01	$	0.21	$	0.17	$	0.05	$	0.22	$	0.03		$	(0.04	)	$	(0.01	)
East Texas	0.18		0.02		0.20		0.26		0.10		0.36		(0.08		)	(0.08		)	(0.16		)	0.20		0.01		0.21		0.24		0.08		0.32		(0.04		)	(0.07		)	(0.11		)
South Texas	0.86		0.04		0.90		1.52		0.11		1.63		(0.66		)	(0.07		)	(0.73		)	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		0.01		0.65		(0.25		)	(0.01		)	(0.26		)	0.39		—		0.39		0.64		0.03		0.67		(0.25		)	(0.03		)	(0.28		)
Total	$	0.31	$	0.01	$	0.32	$	0.39	$	0.07	$	0.46	$	(0.08	)	$	(0.06	)	$	(0.14	)	$	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 ~~six~~nine months ended ~~June~~September 30, 2016 decreased by ~~$6.6~~$3.9 million, or ~~47%~~31%, and ~~$12.0~~$15.9 million, or ~~41%~~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, ~~repairs~~repair and maintenance costs, chemical treatment costs, workover activity and saltwater disposal costs. Reduced labor costs were primarily due to significant reductions in our

workforce in ~~2015.~~2015 and 2016. We ~~expect our lease operating expenses in the Appalachia region to continue to decline during the remainder of 2016 due to the sale of~~sold our conventional assets in Pennsylvania and ~~associated reduction~~West Virginia in ~~workforce.~~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 ~~June~~September 30, 2016 increased by ~~$2.1~~$4.2 million, or 9%18%, as compared with the same period in 2015. Gathering and transportation expenses for the ~~six~~nine months ended ~~June~~September 30, 2016 increased by ~~$3.0~~$5.6 million, or 6%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, ~~which also resulted~~and higher gathering costs on volumes from wells recently turned-to-sales in ~~improved realized natural gas prices.~~North Louisiana. Gathering and transportation expenses were ~~$1.00~~$1.06 per Mcfe for the three months ended ~~June~~September 30, 2016 as compared to ~~$0.75~~$0.76 per Mcfe for the same period in 2015. Gathering and transportation expenses for the ~~six~~nine months ended ~~June~~September 30, 2016 were $0.99 per Mcfe as compared to ~~$0.80~~$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 ~~six~~nine months ended ~~June~~September 30, 2016 and 2015:


	Three Months Ended June 30,												Three Months Ended September 30,
	2016						2015						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		Production and ad valorem taxes		% of revenue		Taxes $/Mcfe		Production and ad valorem taxes		% of revenue		Taxes $/Mcfe
Producing region:
North Louisiana	$	2,155	11.3	%	$	0.16	$	2,468	5.2	%	$	0.12	$	1,627	4.7	%	$	0.11	$	2,431	6.2	%	$	0.13
East Texas	237		1.9	%	0.03		174		1.9	%	0.05		277		1.7	%	0.04		522		4.2	%	0.11
South Texas	2,198		13.2	%	0.75		2,607		8.7	%	0.67		1,626		10.9	%	0.65		2,592		10.2	%	0.64
Appalachia and other	267		4.5	%	0.07		354		5.1	%	0.08		281		6.1	%	0.09		399		6.2	%	0.09
Total	$	4,857	9.0	%	$	0.18	$	5,603	6.0	%	$	0.17	$	3,811	5.4	%	$	0.14	$	5,944	7.1	%	$	0.19

	Six Months Ended June 30,												Nine Months Ended September 30,
	2016						2015						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		Production and ad valorem taxes		% of revenue		Taxes $/Mcfe		Production and ad valorem taxes		% of revenue		Taxes $/Mcfe
Producing region:
North Louisiana	$	4,282	10.4	%	$	0.16	$	4,962	5.3	%	$	0.13	$	5,909	7.8	%	$	0.14	$	7,393	5.5	%	$	0.13
East Texas	587		2.5	%	0.05		300		1.4	%	0.04		864		2.2	%	0.05		822		2.4	%	0.07
South Texas	4,277		14.0	%	0.66		4,707		9.5	%	0.66		5,903		13.0	%	0.66		7,299		9.7	%	0.65
Appalachia and other	351		3.2	%	0.05		495		3.2	%	0.06		632		4.1	%	0.06		894		4.1	%	0.07
Total	$	9,497	9.0	%	$	0.18	$	10,464	5.8	%	$	0.17	$	13,308	7.5	%	$	0.17	$	16,408	6.2	%	$	0.17

Production and ad valorem taxes for the three months ended ~~June~~September 30, 2016 decreased by ~~$0.7~~$2.1 million, or ~~13%~~36%, as compared with the same period in ~~2015.~~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 ~~six~~nine months ended ~~June~~September 30, 2016 decreased by ~~$1.0~~$3.1 million, or 9%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. ~~The decrease was partially offset by higher ad valorem taxes resulting from additional wells drilled and increased ad valorem tax rates in certain counties in Texas.~~

In our North Louisiana region, we currently receive severance tax holidays ~~on certain horizontal wells~~ that reduce the effective rate ~~of these taxes.~~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 ended ~~June~~September 30, 2016 decreased from the same period in 2015 primarily due to a decrease in depletion expense of ~~$42.4~~$36.0 million, or ~~69%~~70%. On a per Mcfe basis, the depletion rate for the three months ended ~~June~~September 30, 2016 was ~~$0.69~~$0.59 per Mcfe, compared with ~~$1.86~~$1.65 per Mcfe in the same period in 2015. Depletion, depreciation and amortization for the ~~six~~nine months ended ~~June~~September 30, 2016 decreased from the same period in 2015 primarily due to a decrease in depletion expense of ~~$75.7~~$111.7 million, or ~~62%~~64%. On a per Mcfe basis, the depletion rate for the ~~six~~nine months ended ~~June~~September 30, 2016 was ~~$0.88~~$0.78 per Mcfe, compared with ~~$1.94~~$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 ~~recorded impairments~~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 ~~$26.2~~$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 ~~$160.8 million~~$1.0 billion for the three and ~~six~~nine months ended ~~June~~September 30, ~~2016,~~2015, respectively. The impairments ~~in both periods~~ were primarily due to the significant decline in oil and natural gas prices. The trailing twelve-month reference prices at June 30, 2016 were $2.24 per Mmbtu of natural gas and $43.12 per Bbl of oil. The spot prices on the first day of July 2016 were $2.92 per Mmbtu of natural gas and $48.85 per Bbl of oil, which exceeded the trailing twelve-month reference prices at June 30, 2016. However, oilOil 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 ~~June~~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.

General and administrative

The following table presents our general and administrative expenses for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015:


	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended September 30,									Nine Months Ended September 30,
(in thousands)	2016			2015			Quarter to quarter change			2016			2015			Period to period change			2016			2015			Quarter to quarter change			2016			2015			Period to period change
General and administrative expenses:
Gross general and administrative expenses	$	13,844		$	20,222		$	(6,378	)	$	27,772		$	43,930		$	(16,158	)	$	14,863		$	21,083		$	(6,220	)	$	42,635		$	65,014		$	(22,379	)
Technical services and service agreement charges	(2,066		)	(3,947		)	1,881			(4,393		)	(8,773		)	4,380			(1,312		)	(3,541		)	2,229			(5,705		)	(12,314		)	6,609
Operator overhead reimbursements	(3,365		)	(3,315		)	(50		)	(6,876		)	(6,544		)	(332		)	(3,463		)	(3,328		)	(135		)	(10,339		)	(9,872		)	(467		)
Capitalized salaries	(758		)	(1,802		)	1,044			(1,764		)	(3,898		)	2,134			(759		)	(1,748		)	989			(2,523		)	(5,646		)	3,123
General and administrative expenses, excluding equity-based compensation	7,655			11,158			(3,503		)	14,739			24,715			(9,976		)	9,329			12,466			(3,137		)	24,068			37,182			(13,114		)
Gross equity-based compensation	9,275			2,406			6,869			13,348			5,055			8,293			1,642			1,852			(210		)	14,990			6,906			8,084
Capitalized equity-based compensation	53			(967		)	1,020			(207		)	(1,936		)	1,729			(225		)	(925		)	700			(432		)	(2,861		)	2,429
General and administrative expenses	$	16,983		$	12,597		$	4,386		$	27,880		$	27,834		$	46		$	10,746		$	13,393		$	(2,647	)	$	38,626		$	41,227		$	(2,601	)

General and administrative expenses for the three months ended ~~June~~September 30, 2016 ~~increased~~decreased by ~~$4.4~~$2.6 million, or ~~35%~~20%, compared with the same period in 2015. General and administrative expenses for the ~~six~~nine months ended ~~June~~September 30, 2016 ~~remained consistent~~decreased 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 ~~$5.3~~$7.0 million and ~~$15.3~~$22.3 million for the three and ~~six~~nine months ended ~~June~~September 30, 2016, respectively, primarily due to reductions in our workforce and ~~other~~ employee benefits.

increased consulting and contract labor costs of ~~$1.4~~$0.5 million and $1.8 million for the ~~six~~three and nine months ended ~~June~~September 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 ~~$1.1~~$2.3 million and ~~$2.3~~$4.9 million for the three and ~~six~~nine months ended ~~June~~September 30, 2016, respectively. These decreases reflect our efforts to reduce our general and administrative costs ~~such as office expenses and professional fees. However, we expect our professional fees to increase during~~throughout the ~~remainder of 2016 in connection with the execution of our strategic plan that is focused on restructuring our balance sheet and gathering and transportation contracts.~~organization.

decreased technical services and service agreement recoveries of ~~$1.9~~$2.2 million and ~~$4.4~~$6.6 million for the three and ~~six~~nine months ended ~~June~~September 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 ~~$2.1~~$3.1 million for the three and ~~six~~nine months ended ~~June~~September 30, 2016, respectively, primarily as a result of reduced employee headcount.

increased equity-based compensation of ~~$7.9~~$0.5 million and ~~$10.0~~$10.5 million for the three and ~~six~~nine months ended ~~June~~September 30, 2016, respectively. These increases were primarily due to ~~$8.9~~$0.7 million and ~~$10.9~~$11.6 million of additional compensation expense related to the warrants issued to ESAS in 2015 for the three and ~~six~~nine months ended ~~June~~September 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 ~~June~~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 ~~losses~~gain of $~~24.9~~1.1 million and a net loss of $~~25.0~~23.9 million for the three and ~~six~~nine months ended ~~June~~September 30, ~~2016. The net losses for both periods were~~2016 primarily due to ~~a loss of $24.3 million~~ ~~recorded during the second quarter of 2016 in connection with~~ the settlement of the litigation with our joint venture ~~partner.~~partner. See "Note ~~13. Subsequent events"~~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 ~~six~~nine months ended ~~June~~September 30, 2016 and 2015:


	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended September 30,									Nine Months Ended September 30,
(in thousands)	2016			2015			Quarter to quarter change			2016			2015			Period to period change			2016			2015			Quarter to quarter change			2016			2015			Period to period change
Interest expense, net:
EXCO Resources Credit Agreement	$	1,195		$	2,019		$	(824	)	$	2,305		$	3,648		$	(1,343	)	$	1,585		$	2,024		$	(439	)	$	3,890		$	5,672		$	(1,782	)
Fairfax Term Loan	9,375			—			9,375			18,750			—			18,750			9,375			—			9,375			28,125			—			28,125
2018 Notes	2,606			14,420			(11,814		)	5,505			28,833			(23,328		)	2,571			14,426			(11,855		)	8,076			43,259			(35,183		)
2022 Notes	4,137			10,625			(6,488		)	8,307			21,250			(12,943		)	2,512			10,625			(8,113		)	10,819			31,875			(21,056		)
Amortization of deferred financing costs	1,866			1,742			124			4,868			6,267			(1,399		)	2,184			3,745			(1,561		)	7,052			10,012			(2,960		)
Capitalized interest	(1,303		)	(3,293		)	1,990			(2,642		)	(7,027		)	4,385			(1,297		)	(3,094		)	1,797			(3,939		)	(10,121		)	6,182
Other	56			58			(2		)	96			90			6			67			35			32			163			125			38
Total interest expense, net	$	17,932		$	25,571		$	(7,639	)	$	37,189		$	53,061		$	(15,872	)	$	16,997		$	27,761		$	(10,764	)	$	54,186		$	80,822		$	(26,636	)

Interest expense, net for the three and ~~six~~nine months ended ~~June~~September 30, 2016 decreased ~~$7.6~~$10.8 million and ~~$15.9~~$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 ~~generally accepted accounting principles in the United States ("GAAP"),~~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.

Derivative financial instruments

Our oil and natural gas derivative financial instruments resulted in net ~~losses~~gains of ~~$36.4~~$8.2 million and ~~$6.6~~$37.3 million for the three months ended ~~June~~September 30, 2016 and 2015, respectively. Our oil and natural gas derivative financial instruments resulted in a net loss of ~~$19.8~~$11.6 million for the ~~six~~nine months ended ~~June~~September 30, 2016 and a net gain of ~~$17.1~~$54.4 million for the ~~six~~nine months ended ~~June~~September 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 June 30,							Six Months Ended June 30,							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			2016		2015		Quarter to quarter change			2016		2015		Period to period change
Natural gas (per Mcf):
Net price, excluding derivatives	$	1.49	$	2.12	$	(0.63	)	$	1.51	$	2.25	$	(0.74	)	$	2.27	$	2.05	$	0.22		$	1.77	$	2.19	$	(0.42	)
Cash receipts on derivatives	0.54		0.70		(0.16		)	0.49		0.65		(0.16		)	0.04		0.70		(0.66		)	0.34		0.67		(0.33		)
Net price, including derivatives	$	2.03	$	2.82	$	(0.79	)	$	2.00	$	2.90	$	(0.90	)	$	2.31	$	2.75	$	(0.44	)	$	2.11	$	2.86	$	(0.75	)
Oil (per Bbl):
Net price, excluding derivatives	$	40.25	$	53.11	$	(12.86	)	$	33.57	$	47.75	$	(14.18	)	$	41.47	$	43.22	$	(1.75	)	$	35.80	$	46.09	$	(10.29	)
Cash receipts on derivatives	7.94		14.73		(6.79		)	10.04		18.36		(8.32		)	9.65		19.97		(10.32		)	9.93		18.95		(9.02		)
Net price, including derivatives	$	48.19	$	67.84	$	(19.65	)	$	43.61	$	66.11	$	(22.50	)	$	51.12	$	63.19	$	(12.07	)	$	45.73	$	65.04	$	(19.31	)
Natural gas equivalent (per Mcfe):
Net price, excluding derivatives	$	2.01	$	2.85	$	(0.84	)	$	1.97	$	2.84	$	(0.87	)	$	2.68	$	2.68	$	—		$	2.20	$	2.79	$	(0.59	)
Cash receipts on derivatives	0.62		0.89		(0.27		)	0.62		0.90		(0.28		)	0.18		1.02		(0.84		)	0.47		0.94		(0.47		)
Net price, including derivatives	$	2.63	$	3.74	$	(1.11	)	$	2.59	$	3.74	$	(1.15	)	$	2.86	$	3.70	$	(0.84	)	$	2.67	$	3.73	$	(1.06	)

Our total cash receipts for the three months ended ~~June~~September 30, 2016 were ~~$16.6~~$4.7 million, or ~~$0.62~~$0.18 per Mcfe, compared to cash receipts of ~~$29.4~~$31.9 million, or ~~$0.89~~$1.02 per Mcfe, for the three months ended ~~June~~September 30, 2015. Our total cash receipts for the ~~six~~nine months ended ~~June~~September 30, 2016 were ~~$33.4~~$38.1 million, or ~~$0.62~~$0.47 per Mcfe, compared to cash receipts of ~~$57.0~~$89.0 million, or ~~$0.90~~$0.94 per Mcfe, for the ~~six~~nine months ended ~~June~~September 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.

Gain on extinguishment of debt

For the three and ~~six~~nine months ended ~~June~~September 30, 2016, we recorded a net ~~gain~~gains on extinguishment of debt of ~~$16.8~~$57.4 million and ~~$62.0~~$119.4 million, respectively. The net gain for the three months ended ~~June~~September 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 ended September 30, 2016 was primarily due to the repurchases of an aggregate of ~~$23.5~~$179.1 million in principal amount of the 2018 Notes and 2022 Notes with an aggregate of ~~$5.4~~$53.3 million in ~~cash. The net gain for~~cash through the ~~six months ended June 30, 2016 was primarily due to the repurchase of an aggregate of $77.8 million in principal amount of the 2018 Notes~~Tender Offer and ~~2022 Notes with an aggregate of $13.3 million in cash.~~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 ~~$0.1~~$0.8 million and ~~$0.5~~$0.2 million for the three months ended ~~June~~September 30, 2016 and 2015, respectively. Our equity loss was ~~$8.0~~$8.8 million and ~~$1.3~~$1.5 million for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, respectively. The increase in our equity loss for the ~~six~~nine months ended ~~June~~September 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 million for the ~~six~~nine months ended ~~June~~September 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 ~~six~~nine months ended ~~June~~September 30, 2016 and 2015 was zero, primarily due to prior losses arising from impairments of oil and natural gas properties ~~which~~that created deferred tax assets. These deferred tax assets have been fully reserved with valuation allowances. Our accumulated valuation allowance as of ~~June~~September 30, 2016 was approximately $1.4 billion and ~~can be used to~~has fully offset ~~future taxable income.~~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 ~~six~~nine months ended ~~June~~September 30, 2016, we had cancellation of debt income for tax purposes which reduced our net operating loss carryforwards ("NOLs") by ~~$64.5~~$125.8 million.

The effective income tax rates, excluding the impact of the valuation allowances, would have been ~~39.0%~~38.3% and ~~38.5%~~38.1% for the three and ~~six~~nine months ended ~~June~~September 30, 2016, respectively, and 38.5% and ~~38.8%~~38.7% for the three and ~~six~~nine months ended ~~June~~September 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 ~~June~~September 30, 2016, we recognized deferred income tax expense of ~~$0.7~~$1.0 million and $1.8 million, respectively, related to a deferred tax liability for tax deductible goodwill. During the ~~three~~nine months ended ~~June~~September 30, 2016, the book basis of goodwill exceeded the tax basis ~~which~~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 ~~net operating loss carryforwards.~~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 ~~are~~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; ~~and~~

our ability to maintain compliance with debt ~~covenants.~~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 ~~lead to~~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 ~~20%~~26%, and reduced our field employees in the Appalachia region by ~~52%~~85% in conjunction with the sale of our conventional assets in ~~Pennsylvania.~~Pennsylvania and West Virginia. We currently employ 191 persons as compared to 315 at December 31, 2015.

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 remains subject to semi-annual review~~Agreement. During the nine months ended September 30, 2016, through the Tender Offer and ~~redetermination by the lenders pursuant to the terms~~a series of ~~the EXCO Resources Credit Agreement, and the next scheduled redetermination of the borrowing base is set to occur on or about September 1, 2016.~~

~~We completed transactions focused on reducing our indebtedness, including~~ open market repurchases, ofwe repurchased an aggregate of $26.4 million and ~~$51.4~~$152.7 million in principal amount of the 2018 Notes and 2022 Notes, respectively, with an aggregate of ~~$13.3~~$53.3 million in ~~cash during the six months ended June 30, 2016.~~cash. As a result, we reduced the principal amounts outstanding under our 2018 Notes and 2022 Notes to $131.6 million and ~~$171.4~~$70.2 million, respectively. ~~During~~

On September 1, 2016, the ~~second quarter of 2016, our cash flows from operations, reduced capital program and proceeds received from the sale of certain assets in South Texas allowed us to reduce our indebtedness~~lenders under the EXCO Resources Credit Agreement ~~by $11.4 million. These transactions resulted~~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 ~~a reduction~~progress. There is no assurance that we will be able to amend the EXCO Resources Credit Agreement and our lenders have discretion in the ~~principal~~timing and amount ~~of outstanding indebtedness by $23.7 million, net of~~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 ~~for~~that would result in their aggregate exposure to exceed $300.0 million, including letters of credit, until the ~~six~~effective date of the postponed redetermination.

During the three months ended ~~June~~September 30, ~~2016.~~

~~On July 27,~~ 2016, we ~~announced~~borrowed an additional $93.0 million under the ~~commencement of a~~EXCO Resources Credit Agreement primarily to fund the Tender Offer ~~for our outstanding 2018 Notes~~repurchases, interest payments and ~~2022 Notes up~~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 ~~maximum combined amount~~letter of ~~$40.0 million~~credit. Furthermore, the limitation on the aggregate ~~price paid.~~ 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.

Our ~~decision~~plans to ~~commence~~improve near-term liquidity primarily include the Tender Offer process is part of EXCO’s comprehensive restructuring process focused on reducing indebtedness. We are also evaluating transactions that could further enhance our liquidity and capital structure including the exchanges of existing indebtedness for common shares, issuance of additional indebtedness ~~restructuring or repurchase~~and we are engaged in discussions with potential lenders. The availability and terms of ~~existing indebtedness, issuance of equity,~~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 ~~certain other commercial contracts, cost reductions, divestitures~~the actions of ~~assets or similar transactions.~~counterparties. There is no assurance any such transactions will occur.

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


(in thousands)	June 30, 2016		September 30, 2016
EXCO Resources Credit Agreement	$	121,592	$	214,592
Exchange Term Loan (1)	400,000		400,000
Fairfax Term Loan	300,000		300,000
2018 Notes (2)	131,576		131,576
2022 Notes	171,432		70,169
Total debt (3)	$	1,124,600	$	1,116,337
Net debt	$	1,071,552	$	1,094,369
Borrowing base(4)	$	325,000	$	300,000
Unused borrowing base ~~(4)~~(5)	$	193,172	$	75,372
Cash ~~(5)~~(6)	$	53,048	$	21,968
Unused borrowing base plus cash	$	246,220	$	97,340


(1)	Amount presented is the outstanding principal balance and excludes ~~$215.9~~$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 ~~$0.7~~$0.6 million at ~~June~~September 30, 2016.


(3)	Excludes unamortized deferred financing costs of ~~$15.4~~$12.8 million at ~~June~~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.


~~(4)~~	~~Net of $10.2 million in letters of credit at June 30, 2016.~~


~~(5)~~(6)	Includes restricted cash of ~~$25.5~~$18.4 million at ~~June~~September 30, 2016.

Credit agreements and long-term debt

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

As of ~~June~~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~~Consolidated Current Ratio of ~~1.2~~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 ~~includes~~include unused commitments under the EXCO Resources Credit ~~Agreement;~~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 ~~1.9~~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 ~~0.8~~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

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 ~~for~~or have sufficient liquidity to conduct our business operations during the next twelve-month period following the date of these Condensed Consolidated Financial Statements.

If we are successful in the Tender Offer, the purchases are expected to be funded primarily with the borrowings under the EXCO Resources Credit Agreement. There can be no assurances regarding the success or extent of the purchases of the senior unsecured notes as part of the Tender Offer process. Furthermore, the The next borrowing base redetermination under the EXCO Resources Credit Agreement is ~~scheduled~~expected to occur ~~on or about September 1,~~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.

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 under the EXCO Resources Credit Agreement in the definition of consolidated current assets. 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 to fund the Tender Offer or further reductions to our borrowing base as part of the upcoming redetermination process would negatively impact our consolidated current ratio and liquidity.

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 ~~current ratio for the twelve-month period following the date of these Condensed~~ Consolidated ~~Financial Statements. We expect to maintain compliance with the minimum requirements for the financial covenants in the EXCO Resources Credit Agreement related to the Interest Coverage~~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 ~~include~~included drilling 76 gross ~~(5.4~~(5.2 net) wells and completing 1514 gross ~~(9.0~~(8.8 net) wells. We have flexibility in the timing of development because our acreage is predominantly held-by-production.

For the ~~six~~nine months ended ~~June~~September 30, 2016, our capital expenditures totaled ~~$56.3~~$69.7 million, of which ~~$52.6~~$60.3 million was related to drilling and development activities. Our development program during the ~~six~~nine months ended ~~June~~September 30, 2016 included an average of one operated drilling rig focused on the Haynesville shale in North Louisiana. We concluded our

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 ~~six~~nine months ended ~~June~~September 30, 2016 and our forecasted capital expenditures for the remainder of 2016.


	Six Months Ended		July - December Forecast		Full Year Forecast		Nine Months Ended		October - December Forecast		Full Year Forecast
(in thousands)	June 30, 2016		2016		2016		June 30, 2016		2016		2016
Capital expenditures:
Development capital expenditures	$	52,583	$	16,417	$	69,000	$	60,285	$	2,215	$	62,500
Other (1)	3,742		12,258		16,000		9,406		13,094		22,500
Total	$	56,325	$	28,675	$	85,000	$	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 ~~six~~nine months ended ~~June~~September 30, 2016 were cash flows from operations and borrowings under the EXCO Resources Credit Agreement.

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


	Six Months Ended June 30,						Nine Months Ended September 30,
(in thousands)	2016			2015			2016			2015
Net cash provided by operating activities	$	45,925		$	108,204
Net cash provided by (used in) operating activities							$	(3,740	)	$	126,856
Net cash used in investing activities	(43,233		)	(192,569		)	(56,150		)	(255,854		)
Net cash provided by financing activities	12,624			87,967			51,177			103,204
Net increase in cash	$	15,316		$	3,602
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 ~~six~~nine months ended ~~June~~September 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 ~~was $45.9 million as compared to $108.2 million~~ for the ~~six~~nine months ended ~~June~~September 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 ~~$33.4~~$38.1 million for the ~~six~~nine months ended ~~June~~September 30, 2016 compared to ~~$57.0~~$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.

For the ~~six~~nine months ended ~~June~~September 30, 2016, our net cash used in investing activities was ~~$43.2~~$56.2 million ~~which~~that primarily consisted of ~~$55.0~~$70.5 million of completion activities in the East Texas region and development activities in the North Louisiana region. This was partially offset by ~~$11.5~~$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.~~wells and other divestitures. For the ~~six~~nine months ended ~~June~~September 30, 2015, our net cash used in investing activities was ~~$192.6~~$255.9 million primarily due to drilling and ~~development~~completion activities in the East Texas, North Louisiana and South Texas regions. The cash used in investing activities for the ~~six~~nine months ended ~~June~~September 30, 2015 included a significant amount of expenditures related to the wells drilled in 2014.

Financing activities

For the ~~six~~nine months ended ~~June~~September 30, 2016, our net cash provided by financing activities was ~~$12.6~~$51.2 million primarily due to ~~$54.1~~$147.1 million in net borrowings under the EXCO Resources Credit Agreement partially offset by payments of ~~$25.3~~$38.1 million on the Exchange Term Loan, which reduced its carrying value, and an aggregate of ~~$13.3~~$53.3 million of cash payments used to repurchase a portion of our 2018 Notes and 2022 Notes. ~~The borrowings under the EXCO Resources Credit Agreement were primarily utilized to fund our investing activities.~~ 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 ~~six~~nine months ended ~~June~~September 30, 2015, our net cash provided by financing activities was ~~$88.0~~$103.2 million primarily due to ~~$90.0~~$97.5 million in borrowings under the EXCO Resources Credit ~~Agreement.~~

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 ~~June~~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		NYMEX gas volume - Bbtu	Weighted average contract price per Mmbtu		NYMEX oil volume - Mbbl	Weighted average contract price per Bbl
Swaps:
Remainder of 2016	28,520	$	2.88	552	$	58.61	14,260	$	2.88	276	$	58.61
2017	23,700	2.99		183	50.00		23,700	2.99		183	50.00
2018	3,650	3.15		—	—		3,650	3.15		—	—
Swaptions:
2017	7,300	2.76		—	—		7,300	2.76		—	—
Collars:
2017	3,650			—			10,950			—
Sold call		3.43			—			3.28			—
Purchased put		2.80			—			2.87			—

We had derivative financial instruments that covered approximately ~~58%~~60% and ~~52%~~55% of production volumes during the three and ~~six~~nine months ended ~~June~~September 30, ~~2016.~~2016, respectively.

See further details on our derivative financial instruments in "Note 7. Derivative financial instruments" and "Note 9.10. Fair value measurements" in the Notes to our Condensed Consolidated Financial Statements.

Off-balance sheet arrangements

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

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 ~~13. Subsequent events"~~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 ~~six~~nine months ended ~~June~~September 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 ~~$28.2~~$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 ~~June~~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

Statements. At ~~June~~September 30, 2016, we had approximately ~~$121.6~~$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 ~~June~~September 30, 2016 would result in an increase in our interest expense of approximately ~~$1.2~~$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 ~~June~~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 ~~June~~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

InDuring the ~~ordinary course~~third quarter of ~~business,~~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 ~~periodically~~also seeking a ~~party~~declaration that we properly terminated the contracts with Enterprise and Acadian, as well as payment of the amounts owed to ~~various litigation matters. As described in "Item 3. Legal Proceedings"~~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.

As of September 30, 2016, we were in ~~a dispute subject to litigation over~~compliance with the ~~offer and the acceptance process with our joint venture partner~~financial covenants under the ~~Participation Agreement that has been settled. See "Note 13. Subsequent events" in the Notes~~EXCO Resources Credit Agreement. If we are not able to execute transactions to improve our ~~Consolidated Financial Statements for additional information and the description~~financial condition, we do not believe we will be able to comply with all of the ~~settlement pertaining~~covenants under the EXCO Resources Credit Agreement or have sufficient liquidity to ~~this litigation matter.~~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 ~~June~~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)
April 1, 2016 - April 30, 2016 —
$ —
—
$ 192.5
May 1, 2016 - May 31, 2016 —
—
—
192.5
June 1, 2016 - June 30, 2016 —
—
—
192.5
Total —
$ —
—



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.

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:	~~August 3,~~November 2, 2016	/s/ Harold L. Hickey
		Harold L. Hickey
		Chief Executive Officer and President
		(Principal Executive Officer)

		/s/ ~~Richard A. Burnett~~Brian N. Gaebe
		~~Richard A. Burnett~~Brian N. Gaebe
		~~Vice President~~Chief Accounting Officer and ~~Chief Financial Officer~~Corporate Controller
		(Principal ~~Financial~~Accounting Officer)

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 ~~Quarterly~~Current Report on Form 8-K, dated November 24, 2015 and filed on November 25, 2015 and incorporated by reference herein.


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.


~~4.8~~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.


~~4.9~~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.


~~4.10~~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.

~~4.11~~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.

~~4.12~~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.*


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.


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

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.


~~10.45~~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

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.


~~10.46~~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.


~~10.47~~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.


~~10.48~~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.

~~10.49~~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.


~~10.50~~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.


~~10.51~~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.


~~10.52~~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.


~~10.53~~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.


~~10.54~~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.


~~10.55~~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.

~~10.56~~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.


~~10.57~~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.*


~~10.58~~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.*


~~10.59~~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.*


~~10.60~~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.*


~~10.61~~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.*


~~10.62~~	~~Amended and Restated Retention Agreement, dated May 14, 2015, by and between Richard A. Burnett~~ 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

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.

5862

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