UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended September 30, ~~2015~~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 October ~~22, 2015~~28, 2016 was ~~283,052,106.~~282,445,821.

Table of Contents

EXCO RESOURCES, INC.

INDEX



PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	2
	Condensed Consolidated Balance Sheets at September 30, ~~2015~~2016 and December 31, ~~2014~~2015	2
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, ~~2015~~2016 and ~~2014~~2015	43
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, ~~2015~~2016 and ~~2014~~2015	54
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Nine Months Ended September 30, ~~2015~~2016 and ~~2014~~2015	65
	Notes to Condensed Consolidated Financial Statements	76

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2832
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4751
Item 4.	Controls and Procedures	4752

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	4852
Item 1A.	Risk Factors	4852
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4953
Item 6.	Exhibits	4953
	Signatures	5054

~~Table of Contents~~

PART I—FINANCIAL INFORMATION


Item 1.	Financial Statements

~~EXCO RESOURCES, INC.~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

(in thousands) September 30,
2015 December 31,
2014
(Unaudited)
Assets
Current assets:
Cash and cash equivalents $ 20,511
$ 46,305
Restricted cash 21,454
23,970
Accounts receivable, net:
Oil and natural gas 60,732
81,720
Joint interest 22,986
65,398
Other 17,159
8,945
Derivative financial instruments 55,000
97,278
Inventory and other 7,640
7,150
Total current assets 205,482
330,766
Equity investments 55,036
55,985
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized 119,046
276,025
Proved developed and undeveloped oil and natural gas properties 3,234,377
3,852,073
Accumulated depletion (2,588,970 ) (2,414,461 )
Oil and natural gas properties, net 764,453
1,713,637
Other property and equipment, net 27,802
24,644
Deferred financing costs, net 24,670
30,636
Derivative financial instruments 9,007
2,138
Deferred income taxes 18,749
35,935
Goodwill 163,155
163,155
Total assets $ 1,268,354
$ 2,356,896

~~See accompanying notes.~~

~~Table of Contents~~

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS


(in thousands, except per share and share data)	September 30, 2015			December 31, 2014
(in thousands)							September 30, 2016			December 31, 2015
	(Unaudited)						(Unaudited)
Assets
Current assets:
Cash and cash equivalents							$	3,534		$	12,247
Restricted cash							18,434			21,220
Accounts receivable, net:
Oil and natural gas							53,439			37,236
Joint interest							17,949			22,095
Other							3,871			8,894
Derivative financial instruments							5,952			39,499
Inventory and other							7,630			8,610
Total current assets							110,809			149,801
Equity investments							31,973			40,797
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized							93,511			115,377
Proved developed and undeveloped oil and natural gas properties							2,946,641			3,070,430
Accumulated depletion							(2,690,611		)	(2,627,763		)
Oil and natural gas properties, net							349,541			558,044
Other property and equipment, net							24,058			27,812
Deferred financing costs, net							5,000			8,408
Derivative financial instruments							1,455			6,109
Goodwill							163,155			163,155
Total assets							$	685,991		$	954,126
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	100,309		$	110,211		$	56,056		$	88,049
Revenues and royalties payable	129,101			152,651			121,312			106,163
Drilling advances	12,825			37,648
Accrued interest payable	22,504			26,265			3,774			7,846
Current portion of asset retirement obligations	1,769			1,769			428			845
Income taxes payable	—			—			—			—
Deferred income taxes	18,749			35,935
Derivative financial instruments	3			892			10,353			16
Current maturities of long-term debt							50,000			50,000
Total current liabilities	285,260			365,371			241,923			252,919
Long-term debt	1,545,106			1,446,535			1,256,068			1,320,279
Deferred income taxes							1,775			—
Derivative financial instruments	30			—			1,189			—
Asset retirement obligations and other long-term liabilities	38,434			34,986			22,626			43,251
Shareholders’ equity:
Common shares, $0.001 par value; 780,000,000 authorized shares; 283,655,812 shares issued and 283,061,149 shares outstanding at September 30, 2015; 274,351,756 shares issued and 273,773,714 shares outstanding at December 31, 2014	276			270
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	3,518,523			3,502,209			3,537,393			3,522,153
Accumulated deficit	(4,111,643		)	(2,984,860		)	(4,367,634		)	(4,177,120		)
Treasury shares, at cost; 594,663 shares at September 30, 2015 and 578,042 at December 31, 2014	(7,632		)	(7,615		)
Treasury shares, at cost; 594,663 shares at September 30, 2016 and December 31, 2015							(7,632		)	(7,632		)
Total shareholders’ equity	(600,476		)	510,004			(837,590		)	(662,323		)
Total liabilities and shareholders’ equity	$	1,268,354		$	2,356,896		$	685,991		$	954,126

See accompanying notes.

~~Table of Contents~~

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands, except per share data)	2015			2014			2015			2014			2016			2015			2016			2015
Revenues:
Oil	$	27,444		$	50,746		$	79,872		$	159,131		$	16,215		$	27,444		$	49,688		$	79,872
Natural gas	56,082			100,296			183,716			373,349			54,647			56,300			127,044			184,275
Purchased natural gas and marketing													6,324			6,773			15,335			21,012
Total revenues	83,526			151,042			263,588			532,480			77,186			90,517			192,067			285,159
Costs and expenses:
Oil and natural gas operating costs	12,669			14,099			41,745			48,713			8,797			12,669			25,835			41,745
Production and ad valorem taxes	5,944			7,978			16,408			22,951			3,811			5,944			13,308			16,408
Gathering and transportation	23,743			25,822			74,243			76,473			27,979			23,743			79,828			74,243
Purchased natural gas													6,586			6,991			17,273			21,571
Depletion, depreciation and amortization	52,013			64,913			176,160			201,441			15,910			52,013			63,995			176,160
Impairment of oil and natural gas properties	339,393			—			1,010,047			—			—			339,393			160,813			1,010,047
Accretion of discount on asset retirement obligations	574			709			1,698			2,085			325			574			2,006			1,698
General and administrative	13,393			14,059			41,227			50,901			10,746			13,393			38,626			41,227
Other operating items	(228		)	663			1,118			6,382			(1,110		)	(228		)	23,936			1,118
Total costs and expenses	447,501			128,243			1,362,646			408,946			73,044			454,492			425,620			1,384,217
Operating income (loss)	(363,975		)	22,799			(1,099,058		)	123,534			4,142			(363,975		)	(233,553		)	(1,099,058		)
Other income (expense):
Interest expense, net	(27,761		)	(23,974		)	(80,822		)	(70,106		)	(16,997		)	(27,761		)	(54,186		)	(80,822		)
Gain (loss) on derivative financial instruments	37,348			42,844			54,427			(14,896		)	8,209			37,348			(11,632		)	54,427
Gain on extinguishment of debt													57,421			—			119,374			—
Other income	21			53			119			176			12			21			37			119
Equity income (loss)	(152		)	(153		)	(1,452		)	548
Equity loss													(823		)	(152		)	(8,824		)	(1,452		)
Total other income (expense)	9,456			18,770			(27,728		)	(84,278		)	47,822			9,456			44,769			(27,728		)
Income (loss) before income taxes	(354,519		)	41,569			(1,126,786		)	39,256			51,964			(354,519		)	(188,784		)	(1,126,786		)
Income tax expense	—			—			—			—			1,028			—			1,775			—
Net income (loss)	$	(354,519	)	$	41,569		$	(1,126,786	)	$	39,256		$	50,936		$	(354,519	)	$	(190,559	)	$	(1,126,786	)
Earnings (loss) per common share:
Basic:
Net income (loss)	$	(1.30	)	$	0.15		$	(4.14	)	$	0.15		$	0.18		$	(1.30	)	$	(0.68	)	$	(4.14	)
Weighted average common shares outstanding	273,348			270,631			272,147			267,316			279,873			273,348			279,008			272,147
Diluted:
Net income (loss)	$	(1.30	)	$	0.15		$	(4.14	)	$	0.15		$	0.18		$	(1.30	)	$	(0.68	)	$	(4.14	)
Weighted average common shares and common share equivalents outstanding	273,348			272,066			272,147			267,690			281,045			273,348			279,008			272,147

See accompanying notes.

~~Table of Contents~~

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2015			2014			2016			2015
Operating Activities:
Net income (loss)	$	(1,126,786	)	$	39,256
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net loss							$	(190,559	)	$	(1,126,786	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Deferred income tax expense							1,775			—
Depletion, depreciation and amortization	176,160			201,441			63,995			176,160
Equity-based compensation expense	4,045			4,370			14,558			4,045
Accretion of discount on asset retirement obligations	1,698			2,085			2,006			1,698
Impairment of oil and natural gas properties	1,010,047			—			160,813			1,010,047
(Income) loss from equity method investments	1,452			(548		)
Loss from equity investments							8,824			1,452
(Gain) loss on derivative financial instruments	(54,427		)	14,896			11,632			(54,427		)
Cash receipts (payments) of derivative financial instruments	88,977			(32,187		)
Cash receipts of derivative financial instruments							38,097			88,977
Amortization of deferred financing costs and discount on debt issuance	11,083			9,891			7,250			11,083
Other non-operating items	(13		)	(8		)	24,068			(13		)
Gain on extinguishment of debt							(119,374		)	—
Effect of changes in:
Restricted cash with related party	(1,500		)	—			2,100			(1,500		)
Accounts receivable	59,238			60,201			(12,752		)	59,238
Other current assets	1,062			(1,135		)	(1,207		)	1,062
Accounts payable and other current liabilities	(44,180		)	60,103
Net cash provided by operating activities	126,856			358,365
Accounts payable and other liabilities							(14,966		)	(44,180		)
Net cash provided by (used in) operating activities							(3,740		)	126,856
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment	(269,708		)	(297,736		)	(70,455		)	(269,708		)
Property acquisitions	(7,608		)	(12,987		)	—			(7,608		)
Proceeds from disposition of property and equipment	7,397			76,536			11,242			7,397
Restricted cash	4,016			(1,389		)	686			4,016
Net changes in advances to joint ventures	8,594			(3,181		)	2,377			8,594
Equity investments and other	1,455			1,749			—			1,455
Net cash used in investing activities	(255,854		)	(237,008		)	(56,150		)	(255,854		)
Financing Activities:
Borrowings under credit agreements	97,500			40,000
Repayments under credit agreements	—			(884,970		)
Proceeds received from issuance of 2022 Notes	—			500,000
Borrowings under EXCO Resources Credit Agreement							390,897			97,500
Repayments under EXCO Resources Credit Agreement							(243,797		)	—
Payments on Exchange Term Loan							(38,056		)	—
Repurchases of senior unsecured notes							(53,298		)	—
Proceeds from issuance of common shares, net	9,829			271,760			—			9,829
Payments of common share dividends	(62		)	(40,604		)
Deferred financing costs and other	(4,063		)	(10,076		)	(4,569		)	(4,125		)
Net cash provided by (used in) financing activities	103,204			(123,890		)
Net cash provided by financing activities							51,177			103,204
Net decrease in cash	(25,794		)	(2,533		)	(8,713		)	(25,794		)
Cash at beginning of period	46,305			50,483			12,247			46,305
Cash at end of period	$	20,511		$	47,950		$	3,534		$	20,511
Supplemental Cash Flow Information:
Cash interest payments	$	81,913		$	69,257		$	51,975		$	81,913
Income tax payments	—			—			—			—
Supplemental non-cash investing and financing activities:
Capitalized equity-based compensation	$	2,861		$	4,432		$	432		$	2,861
Capitalized interest	10,121			15,410			3,939			10,121
Issuance of common shares for director services	150			185

See accompanying notes.

~~Table of Contents~~

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


	Common shares			Subscription rights					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			Shares		Amount							Accumulated deficit			Shares					Amount			Shares	Amount					Additional paid-in capital		Accumulated deficit			Total shareholders’ equity
Balance at December 31, 2013	218,783	$	215	54,575		$	55		(539	)	$	(7,479	)	Additional paid-in capital		$	3,219,748			$	(3,064,634	Total shareholders’ equity	)		$	147,905
Issuance of common shares	54,582	55		(54,575	)	(55		)	—		—			271,945				—				271,945
Equity-based compensation	—	—		—		—			—		—			8,795				—				8,795
Restricted shares issued, net of cancellations	959	—		—		—			—		—			—				—				—
Common share dividends	—	—		—		—			—		—			—				(40,859		)		(40,859		)
Net income	—	—		—		—			—		—			—				39,256				39,256
Balance at September 30, 2014	274,324	$	270	—		$	—		(539	)	$	(7,479	)	$	3,500,488			$	(3,066,237	)		$	427,042
Balance at December 31, 2014	274,352	$	270	—		$	—		(578	)	$	(7,615	)	$	3,502,209			$	(2,984,860	)		$	510,004			274,352		$	270	(578	)	$	(7,615	)	$	3,502,209	$	(2,984,860	)	$	510,004
Issuance of common shares	5,882	6		—		—			—		—			9,875				—				9,881				5,882		6		—		—			9,875		—			9,881
Equity-based compensation	—	—		—		—			—		—			6,439				—				6,439				—		—		—		—			6,439		—			6,439
Restricted shares issued, net of cancellations	3,422	—		—		—			—		—			—				—				—				3,422		—		—		—			—		—			—
Common share dividends	—	—		—		—			—		—			—				3				3				—		—		—		—			—		3			3
Treasury share repurchases	—	—		—		—			(17	)	(17		)	—				—				(17		)		—		—		(17	)	(17		)	—		—			(17		)
Net loss	—	—		—		—			—		—			—				(1,126,786		)		(1,126,786		)		—		—		—		—			—		(1,126,786		)	(1,126,786		)
Balance at September 30, 2015	283,656	$	276	—		$	—		(595	)	$	(7,632	)	$	3,518,523			$	(4,111,643	)		$	(600,476	)		283,656		$	276	(595	)	$	(7,632	)	$	3,518,523	$	(4,111,643	)	$	(600,476	)
Balance at December 31, 2015																										283,634		$	276	(595	)	$	(7,632	)	$	3,522,153	$	(4,177,120	)	$	(662,323	)
Issuance of common shares																										243		—		—		—			—		—			—
Equity-based compensation																										—		—		—		—			15,240		—			15,240
Restricted shares issued, net of cancellations																										(837	)	7		—		—			—		—			7
Common share dividends																										—		—		—		—			—		45			45
Net loss																										—		—		—		—			—		(190,559		)	(190,559		)
Balance at September 30, 2016																										283,040		$	283	(595	)	$	(7,632	)	$	3,537,393	$	(4,367,634	)	$	(837,590	)

See accompanying notes.

~~Table of Contents~~

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 ~~certain Haynesville/~~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 ~~both~~ the East Texas and North Louisiana regions.

•South Texas

The South Texas region is primarily comprised of our Eagle Ford shale assets. We have a joint venture with affiliates of Kohlberg Kravis Roberts & Co. L.P. ("KKR") to develop certain assets in the Eagle Ford shale. The South Texas region also includes assets outside of the joint venture in the Eagle Ford shale, Buda and other formations. We serve as the operator for most of our properties in the South Texas region.

•Appalachia

The Appalachia region is primarily comprised of Marcellus shale assets as well as shallow conventional assets in other formations. We have a joint venture with BG Group covering our ~~shallow conventional assets and Marcellus shale~~ assets in the Appalachia region ("Appalachia JV"). EXCO and BG Group each own an undivided 50% interest in the Appalachia JV and a 49.75% working interest in the Appalachia JV's properties. The remaining 0.5% working interest is held by a jointly owned operating entity ("OPCO") that operates the Appalachia JV's properties. We own a 50% interest in OPCO. On July 1, 2016, we closed the sale of our interests in shallow conventional assets located in Pennsylvania and retained an overriding royalty interest in each well, and on October 3, 2016, we closed the sale of our interests in shallow conventional assets located in West Virginia. See "Note 3. Divestitures" for additional discussion.

The accompanying Condensed Consolidated Balance Sheets as of September 30, ~~2015~~2016 and December 31, ~~2014,~~2015, Condensed Consolidated Statements of Operations for the three and nine months ended September 30, ~~2015~~2016 and ~~2014,~~2015, Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the nine months ended September 30, ~~2015~~2016 and ~~2014~~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 September 30, ~~2015~~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, ~~2014,~~2015, filed with the SEC on ~~February 25,~~ March 2, 2016 ("2015 ~~as amended by Amendment No. 1 to Annual Report on Form 10-K/A, filed with the SEC on April 10, 2015 ("2014~~ Form 10-K").

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

Going Concern Presumption and Management’s Plans

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

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

As of September 30, 2016, we were in compliance with the financial covenants under the EXCO Resources Credit Agreement. We are required to maintain a Consolidated Current Ratio (as defined in the EXCO Resources Credit Agreement) of at least 1.0 to 1.0 as of the end of any fiscal quarter, which includes unused commitments in the definition of consolidated current assets. The inclusion of the unused commitments has historically allowed us to maintain compliance with the Consolidated Current Ratio covenant under the EXCO Resources Credit Agreement. Therefore, the reduction in unused commitments as a result of borrowings under the EXCO Resources Credit Agreement or further reductions to our borrowing base as part of the redetermination process will negatively impact our Consolidated Current Ratio and liquidity.

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

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

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

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

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

Revisions of prior period information

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

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

The following table reflects the revisions to prior periods:



					Three months ended
(in thousands)					June 30, 2016			March 31, 2016
Gathering and transportation, previously reported					$	26,895		$	26,630
Revision of third party natural gas purchases and sales					(151		)	(1,525		)
Gathering and transportation, as currently reported					$	26,744		$	25,105

Purchased natural gas and marketing revenues					$	4,570		$	4,441
Purchased natural gas expenses					$	4,721		$	5,966

	Three months ended
(in thousands)	December 31, 2015		September 31, 2015		June 30, 2015			March 31, 2015
Natural gas revenues, previously reported	$	41,828	$	56,082	$	62,197		$	65,437
Revision of third party natural gas purchases and sales	368		218		184			157
Natural gas revenues, as currently reported	$	42,196	$	56,300	$	62,381		$	65,594

Purchased natural gas and marketing revenues	$	5,430	$	6,773	$	6,678		$	7,561
Purchased natural gas expenses	$	5,798	$	6,991	$	6,862		$	7,718

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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, ~~share-based~~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 ~~the 2014~~our 2015 Form 10-K.

~~Goodwill~~

We perform an impairment test for goodwill at least annually or more frequently as impairment indicators arise. Our impairment test is typically performed during the fourth quarter; however, we performed an impairment test as of September 30, 2015 as a result of continued depressed commodity prices and recent impairments of oil and natural gas properties. As a result of our testing, the fair value of our business exceeded the carrying value of net assets and we did not record an impairment charge during the third quarter of 2015.

Recent accounting pronouncements

In ~~April 2015,~~August 2016, the ~~Financial Accounting Standards Board ("FASB")~~FASB issued Accounting Standards Update ("ASU") No. ~~2015-03, Interest - Imputation~~2016-15, Statement of ~~Interest (Subtopic 835-30)~~Cash Flows (Topic 230): ~~Simplifying the Presentation~~Classification of ~~Debt Issuance Costs~~Certain Cash Receipts and Cash Payments ("ASU ~~2015-03"~~2016-15"). ASU ~~2015-03 requires that debt issuance costs related to a recognized debt liability be presented~~2016-15 reduces diversity in practice in how certain transactions are classified in the ~~balance sheet as~~statement of cash flows. The amendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a ~~direct deduction~~business combination, proceeds from the ~~carrying amount~~settlement of ~~that debt liability, consistent with debt discounts. We currently recognize debt issuance costs as assets on our balance sheet. The recognition~~insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and ~~measurement guidance for debt issuance costs are not affected by~~distributions received from equity method investees. ASU ~~2015-03. ASU 2015-03~~2016-15 is effective for annual and interim periods beginning after December 15, ~~2015 and early adoption is permitted. In August 2015,~~2017. We are currently assessing the ~~FASB issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30):~~ ~~Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements~~ ("ASU 2015-15"). ASU 2015-15 clarifies that the SEC would not object to an entity deferring and presenting debt issuance costs related to a line-of-credit arrangement as an asset on the balance sheet. We plan to adopt ASU 2015-03 and ASU 2015-15 in the fourth quarter of 2015. The adoptionpotential impact of ASU ~~2015-03 and ASU 2015-15 will result in certain reclassifications of debt issuance costs~~2016-15 on our ~~balance sheets.~~consolidated financial condition and results of operations.

In ~~September 2015,~~May 2016, the FASB issued ASU No. ~~2015-16, Business Combinations~~2016-12, Revenue from Contracts with Customers (Topic ~~805)~~606): ~~Simplifying the Accounting for Measurement-Period Adjustments~~ Narrow-Scope Improvements and Practical Expedients(" ("ASU ~~2015-16"~~2016-12"). ASU ~~2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during~~2016-12 does not change the ~~measurement period in~~core principle of Topic 606 but improves the ~~reporting period in which the adjustment amounts are determined. The amendments in this update require that the acquirer record, in the same period’s financial statements, the effect on earnings~~following aspects of ~~changes in depreciation, amortization, or other income effects, if any, as a result~~Topic 606: assessing collectability, presentation of ~~the change to the provisional amounts, calculated as if the accounting had been~~sales taxes, noncash considerations, completed contracts and contract modifications at the acquisition date. The amendments in this update require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date.transaction. ASU ~~2015-16~~2016-12 is effective for annual and interim periods beginning after December 15, ~~2015~~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 ~~will apply this guidance to business combinations, when applicable, occurring after~~are currently assessing the ~~effective date~~potential impact of ASU ~~2015-16.~~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.~~Acquisitions~~Divestitures

~~Eagle Ford acquisition program~~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 ~~have a participation agreement~~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 ~~a joint venture partner~~the sales of our shallow conventional assets in Pennsylvania and West Virginia, the Company's field employee count in the Eagle Ford shale to mitigate the impact of development expenditures on our capital resources and liquidity ("Participation Agreement"). The Participation Agreement requires us to offer to purchase our joint venture partner's working interest in wells that haveAppalachia region has been on production for at least one year. The offers are made on a quarterly basis for a group of wells based on prices defined in the Participation Agreement, subject to specific well criteria and return hurdles.

We closed the first acquisition of our joint venture partner's interest in 3 gross (1.4 net) wells on March 11, 2015 for a total purchase price of $7.6 million. Our joint venture partner did not accept our second offer for 10 gross (5.2 net) wells in July 2015. The wells included in the offer did not meet the specified return hurdle in the Participation Agreement; therefore, our joint venture partner was not required to sell us the wells included in this offer.

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third offer if our joint venture partner does not accept the preceding offer. The total purchase price in both of the outstanding offers will depend on our joint venture partner's acceptance of the offers as well as our joint venture partner's option to retain an undivided 15% of its collective interest in certain wells. If our joint venture partner accepts these offers, we expect the offer and acceptance process to be completed and the acquisitions to close in the fourth quarter ofreduced by 85% since December 31, 2015.

4.Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the nine months ended September 30, ~~2015:~~2016:


(in thousands)
Asset retirement obligations at beginning of period	$	36,755		$	41,648
Activity during the period:
Liabilities incurred during the period	823
Liabilities settled during the period	(128		)	(59		)
Adjustment to liability due to acquisitions	180
Adjustment to liability due to divestitures	(1,192		)
Adjustment to liability due to divestitures (1)				(22,859		)
Accretion of discount	1,698			2,006
Asset retirement obligations at end of period	38,136			20,736
Less current portion	1,769			428
Long-term portion	$	36,367		$	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.

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. As a result of our evaluation, we impaired approximately $84.9 million of unproved properties which were transferred to the depletable portion of the full cost pool during the nine months ended September 30, 2015. The ~~impairment was recorded to reflect the estimated fair value~~majority of our undeveloped properties are held-by-production, which reduces the risk of impairment as a result of ~~the decline in oil and natural gas prices. See "Note 8. Fair value measurements" for further discussion.~~lease expirations. There were no impairments of unproved properties during the nine months ended September 30, ~~2014.~~2016 and we impaired $84.9 million of unproved properties during the nine months ended September 31, 2015.

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

The ceiling test for each period presented was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing ~~12 month~~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

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between each of the periods and have a significant impact on our ceiling test limitation.

Trailing 12 month simple average spot prices
Oil (per Bbl) Natural gas (per Mmbtu)
September 30, 2015 $ 59.21
$ 3.06
June 30, 2015 71.68
3.39
March 31, 2015 82.72
3.88
December 31, 2014 94.99
4.35



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

We did not recognize an impairment to our proved oil and natural gas properties for the three months ended September 30, 2016, and we recognized impairments to our proved oil and natural gas properties of $160.8 million for the nine months ended September 30, 2016. We recognized impairments to our proved oil and natural gas properties of $339.4 million and $1.0 billion for the three and nine months ended September 30, 2015, respectively. The impairments were primarily due to the decline in oil and natural gas prices. ~~We did not recognize impairments~~Furthermore, the fixed costs associated with certain gathering and transportation contracts continue to have a significant impact on the present value of our proved ~~oil~~reserves. Oil and natural gas ~~properties for the three~~prices are volatile and ~~nine months ended September 30, 2014. We~~we may incur additional impairments ~~to our oil and natural gas properties in 2015~~during 2016 if future oil and natural gas prices ~~do not increase.~~result in a decrease in the trailing twelve-month reference prices compared to September 30, 2016. The possibility and amount of any future impairments is difficult to predict, and will depend, in part, upon future oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves, ~~and~~ future capital expenditures and operating costs.

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

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

the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.

6.Earnings (loss) per share

The following table presents the basic and diluted earnings (loss) per share computations for the three and nine months ended September 30, ~~2015~~2016 and ~~2014~~2015:


	Three Months Ended September 30,					Nine Months Ended September 30,					Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands, except per share data)	2015			2014		2015			2014		2016		2015			2016			2015
Basic net income (loss) per common share:
Net income (loss)	$	(354,519	)	$	41,569	$	(1,126,786	)	$	39,256	$	50,936	$	(354,519	)	$	(190,559	)	$	(1,126,786	)
Weighted average common shares outstanding	273,348			270,631		272,147			267,316		279,873		273,348			279,008			272,147
Net income (loss) per basic common share	$	(1.30	)	$	0.15	$	(4.14	)	$	0.15	$	0.18	$	(1.30	)	$	(0.68	)	$	(4.14	)
Diluted net income (loss) per common share:
Net income (loss)	$	(354,519	)	$	41,569	$	(1,126,786	)	$	39,256	$	50,936	$	(354,519	)	$	(190,559	)	$	(1,126,786	)
Weighted average common shares outstanding	273,348			270,631		272,147			267,316		279,873		273,348			279,008			272,147
Dilutive effect of:
Stock options	—			—		—			—		—		—			—			—
Restricted shares and restricted share units	—			1,435		—			374		1,172		—			—			—
Warrants	—			—		—			—		—		—			—			—
Weighted average common shares and common share equivalents outstanding	273,348			272,066		272,147			267,690		281,045		273,348			279,008			272,147
Net income (loss) per diluted common share	$	(1.30	)	$	0.15	$	(4.14	)	$	0.15	$	0.18	$	(1.30	)	$	(0.68	)	$	(4.14	)

Diluted net income (loss) per common share for the three and nine months ended September 30, ~~2015~~2016 and ~~2014~~2015 is computed in the same manner as basic net income (loss) per share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which include stock options, restricted share units, restricted share awards and warrants, whether exercisable or not. The computation of diluted ~~earnings~~net income (loss) per share excluded ~~36,157,630~~88,083,055 and ~~13,122,425~~36,157,630 antidilutive share equivalents for the three months ended September 30, ~~2015~~2016 and ~~2014~~,2015, respectively, and ~~21,200,285~~89,522,616 and ~~13,668,594~~21,200,285 antidilutive share equivalents for the nine months ended September 30, 2016 and 2015, respectively. Our antidilutive share equivalents for the three and ~~2014, respectively.~~nine months ended September 30, 2016 included 80,000,000 warrants issued to Energy Strategic Advisory Services LLC ("ESAS"). See "Note 12. Related party transactions" for additional information on the warrants issued to ESAS. All of our outstanding warrants and stock options were out-of-the-money and considered antidilutive during the three months ended September 30, 2016.

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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)	September 30, 2015			December 31, 2014			September 30, 2016			December 31, 2015
Derivative financial instruments - Current assets	$	55,000		$	97,278		$	5,952		$	39,499
Derivative financial instruments - Long-term assets	9,007			2,138			1,455			6,109
Derivative financial instruments - Current liabilities	(3		)	(892		)	(10,353		)	(16		)
Derivative financial instruments - Long-term liabilities	(30		)	—			(1,189		)	—
Net derivative financial instruments	$	63,974		$	98,524		$	(4,135	)	$	45,592

Effect of Derivative Financial Instruments


	Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2015		2014		2015		2014			2016		2015		2016			2015
Gain (loss) on derivative financial instruments	$	37,348	$	42,844	$	54,427	$	(14,896	)	$	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.

~~Basis swaps~~Swaptions: These contracts allow us to receive a fixed price differential between market indices for oil prices based on the delivery point. Our oil basis swaps typically have a positive differential to NYMEX WTI oil prices.

~~Call options~~: These contracts give our trading counterparties the right, but not the obligation, to ~~buy~~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. ~~At the time of settlement, if the market price exceeds the fixed price of the call~~The counterparty to our swaption contracts can choose to exercise its option we pay the counterparty the excess. If the market price settles below the fixed price of the call option, no payment is due from either party. In exchange for selling this option, we received upfront proceeds which we usedin December 2016 to ~~obtain a higher fixed price on our swaps. These transactions were conducted contemporaneously with a single counterparty and resulted in a net cashless transaction.~~enter into 2017 swap contracts.

~~Three-way collars~~Collars: A ~~three-way~~ collar is a combination of options including a sold call ~~a purchased put~~ and a ~~sold~~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 ~~partial~~ downside protection through the ~~combination of the~~ put ~~options.~~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, unless the market price falls below the strike price of the sold put at which point the counterparty pays us the difference between the strike prices of the purchased put and sold put.~~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.

~~Table of Contents~~

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 September 30, ~~2015~~2016:

(in thousands, except prices) Volume Mmbtu/Bbl Weighted average strike price per Mmbtu/Bbl Fair value at September 30, 2015
Natural gas:
Swaps:
Remainder of 2015 12,650
$ 4.02
$ 17,901
2016 23,790
3.23
10,133
2017 10,950
3.28
3,150
2018 3,650
3.15
345
Call options:
Remainder of 2015 5,060
4.29
(3 )
Three-way collars:
Remainder of 2015 6,900
3,364
Sold call 4.47

Purchased put 3.83

Sold put 3.33

2016 10,980
4,659
Sold call 4.80

Purchased put 3.90

Sold put 3.40

Total natural gas $ 39,549
Oil:
Swaps:
Remainder of 2015 322
$ 86.44
$ 12,873
2016 915
61.89
11,473
Basis swaps:
Remainder of 2015 23
6.10
79
Call options:
Remainder of 2015 92
100.00
—
Total oil $ 24,425
Total oil and natural gas derivative financial instruments $ 63,974



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

At December 31, ~~2014,~~2015, we had outstanding swap ~~call option and three-way collar~~ contracts covering ~~42,888~~49,370 ~~Mmmbtu,~~ ~~20,075~~ ~~Mmmbtu and 38,355 Mmmbtu, respectively,~~Bbtu of natural gas and ~~we had outstanding swap, basis swap and call option contracts covering~~ ~~1,095~~915 Mbbls91 ~~Mbbls and~~ ~~365~~ ~~Mbbls, respectively,~~ of oil.

At September 30, ~~2015~~,2016, the average forward NYMEX WTI oil prices per Bbl for the remainder of ~~2015~~2016 and calendar year ~~2016~~2017 were ~~$45.33,~~$48.53 and ~~$48.70,~~$51.30, respectively, ~~the average forward NYMEX Louisiana Light Sweet ("LLS") oil price per Bbl for the remainder of 2015 was $48.09~~ and the average forward NYMEX HH natural gas prices per Mmbtu for the remainder of ~~2015~~2016 and calendar years ~~2016,~~ 2017 and 2018 were ~~$2.61, $2.80, $2.99~~$3.02, $3.09 and ~~$3.05,~~$2.91, respectively.

Our derivative financial instruments covered approximately ~~69%~~60% and ~~72%~~69% of production volumes for the three months ended September 30, ~~2015~~2016 and ~~2014,~~2015, respectively, and ~~66%~~55% and ~~68%~~66% of production volumes for the nine months ended September 30, 2016 and 2015, respectively.

8.Debt

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



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



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

Terms and conditions of our debt obligations are discussed below.

Tender Offer and open market repurchases

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

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

EXCO Resources Credit Agreement

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

The maturity date of the EXCO Resources Credit Agreement is July 31, 2018. The interest rate grid for the revolving commitment under the EXCO Resources Credit Agreement ranges from London Interbank Offered Rate ("LIBOR") plus 225 bps to 325 bps (or alternate base rate ("ABR") plus 125 bps to 225 bps), depending on our borrowing base usage. On September 30, 2016, our interest rate was approximately 3.5%.

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

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

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

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

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 ~~2014, respectively.~~

~~Table~~$108.7 million on November 4, 2015 (“Exchange Term Loan"). The proceeds from the Exchange Term Loan were used to repurchase a portion of ~~Contents~~the outstanding 2018 Notes and 2022 Notes in exchange for the holders of such notes agreeing to act as lenders in connection with the Exchange Term Loan. The exchange was accounted for as a troubled debt restructuring pursuant to FASB ASC 470-60, Troubled Debt Restructuring by Debtors. The future undiscounted cash flows from the Exchange Term Loan through its maturity were less than the carrying amounts of the retired 2018 Notes and 2022 Notes. As a result, the carrying amount of the Exchange Term Loan is equal to the total undiscounted future cash payments, including interest and principal. All cash payments under the terms of the Exchange Term Loan, whether designated as interest or as principal amount, will reduce the carrying amount and no interest expense will be recognized. As such, our reported interest expense will be less than the contractual payments throughout the term of the Exchange Term Loan.

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

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

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

prepay, redeem or repurchase certain debt;

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

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

enter into transactions with affiliates;

consolidate, merge or dispose of assets;

incur liens; and

enter into sale/leaseback transactions.

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

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

second lien debt in excess of $700.0 million; and

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

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

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

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

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

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

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

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

2018 Notes

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

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

The indenture governing the 2018 Notes contains covenants, which may limit our ability and the ability of our restricted subsidiaries to:

incur or guarantee additional debt and issue certain types of preferred stock;

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

make certain investments;

create liens on our assets;

enter into sale/leaseback transactions;

create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;

engage in transactions with our affiliates;

transfer or issue shares of stock of subsidiaries;

transfer or sell assets; and

consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries.

2022 Notes

The 2022 Notes were issued at 100.0% of the principal amount and bear interest at a rate of 8.5% per annum, payable in arrears on April 15 and October 15 of each year. In the fourth quarter of 2015, EXCO repurchased an aggregate $277.2 million in principal amount of the 2022 Notes in exchange for certain holders of the 2022 Notes becoming lenders under the Exchange Term Loan. On August 24, 2016, we completed the Tender Offer that resulted in the repurchases of an aggregate of $101.3 million in principal amount of the 2022 Notes for an aggregate purchase price of $40.0 million. As of September 30, 2016, through the Tender Offer and a series of open market repurchases, we had repurchased a total of $152.7 million in principal amount of the 2022 Notes for an aggregate of $46.5 million. As a result of the repurchases, the aggregate principal amount of outstanding 2022 Notes was reduced to $70.2 million as of September 30, 2016.

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

The 2022 Notes rank equally in right of payment to any existing and future senior unsecured indebtedness of the Company (including the 2018 Notes) and are guaranteed on a senior unsecured basis by EXCO’s consolidated subsidiaries that are guarantors of the indebtedness under the EXCO Resources Credit Agreement. The 2022 Notes were issued under the same base indenture governing the 2018 Notes and the supplemental indenture governing the 2022 Notes contains similar covenants to those in the supplemental indenture governing the 2018 Notes.

8.9.Commitments and contingencies

Settlement of Participation Agreement litigation

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 ~~rating,~~ratings, futures markets and forward curves, and readily available buyers or sellers. During the nine months ended September 30, ~~2015~~2016 and ~~2014~~2015 there were no changes in the fair value level classifications. The following table presents a summary of the estimated fair value of our derivative financial instruments as of September 30, ~~2015~~2016 and December 31, ~~2014.~~2015.


	September 30, 2015								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	$	—	$	63,974	$	—	$	63,974	$	—	$	(4,135	)	$	—	$	(4,135	)
	December 31, 2014								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	$	—	$	98,524	$	—	$	98,524	$	—	$	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 onin our Condensed Consolidated Balance Sheets. Net derivative asset values are determined primarily by quoted futures prices and utilization of the counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined by utilization of our credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates of our counterparties are based on an independent market-quoted credit default swap rate curve for the counterparties’ debt plus the ~~London Interbank Offered Rate ("LIBOR")~~LIBOR curve as of the end of the reporting period. Our credit-adjusted risk-free rate is based on the blended rate of independent market-quoted credit default swap rate curves for companies that have the same credit rating as us plus the LIBOR curve as of the end of the reporting period.

The valuation of our commodity price derivatives, represented by oil and natural gas swaps, ~~basis swaps, call option~~collars and ~~three-way collar~~swaption contracts, is discussed below.

Oil derivatives. Our oil derivatives are swap ~~basis swap and call option~~ contracts for notional ~~Bbls~~barrels of oil at fixed ~~(in the case of swap and basis swap contracts) or interval (in the case of call option contracts)~~ NYMEX oil index prices. The asset and liability values attributable to our oil derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for oil index prices, and (iii) the applicable credit-adjusted risk-free rate curve, as described ~~above, and (iv) the implied rate of volatility inherent in the call option contracts. The implied rates of volatility were determined based on average NYMEX oil index prices.~~above.

Natural gas derivatives. Our natural gas derivatives are swap, ~~three-way~~ collar and ~~call option~~swaption contracts for notional Mmbtus of natural gas at posted price indexes, including NYMEX HH swap, option and ~~option~~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 ~~HH for~~ natural gas swaps, (iii) the applicable credit-adjusted risk-free rate curve, as described above, and (iv) the implied ~~rate~~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.

~~Table of Contents~~

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 ~~revolving commitment of our credit agreement ("~~EXCO Resources Credit ~~Agreement")~~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 ~~7.5%~~ ~~senior unsecured notes due September 15,~~ 2018 ("Notes, 2022 Notes, Exchange Term Loan and Fairfax Term Loan are presented below. The estimated fair values of the 2018 ~~Notes")~~Notes and ~~our 8.5% senior unsecured notes due April 15,~~ 2022 ~~("2022 Notes")~~Notes have been calculated based on ~~market quotes~~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 ~~presented below.~~classified as Level 2.


	September 30, 2015								September 30, 2016
(in thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
2018 Notes	$	225,000	$	—	$	—	$	225,000	$	60,438	$	—	$	—	$	60,438
2022 Notes	131,840		—		—		131,840		27,366		—		—		27,366
Exchange Term Loan									—		263,500		—		263,500
Fairfax Term Loan									—		197,625		—		197,625
	December 31, 2014								December 31, 2015
(in thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
2018 Notes	$	558,750	$	—	$	—	$	558,750	$	43,170	$	—	$	—	$	43,170
2022 Notes	373,500		—		—		373,500		48,376		—		—		48,376
Exchange Term Loan									—		278,000		—		278,000
Fairfax Term Loan									—		208,500		—		208,500

Other fair value measurements

As discussed in "Note 5. Oil and natural gas properties", we assess our unproved oil and natural gas properties for potential impairment due to an other than temporary trend that would negatively impact the fair value. The continued depressed oil and natural gas prices as well as longer-term commodity price outlooks provided indications of possible impairment. During the nine months ended September 30, ~~2015,~~2016, we impaired ~~approximately $84.9~~$4.9 million of ~~unproved properties~~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. These impairment charges were transferred~~value and is considered to be Level 3 within the ~~depletable portion of the full cost pool. We calculated the~~fair value hierarchy. The estimated fair value of our ~~unproved properties~~cost method investment was determined based on trading metrics of comparable transactions.

As discussed in "Note 9. Commitments and contingencies", we recorded a $23.2 million loss in "Other operating items" in our Condensed Consolidated Statements of Operations for the ~~average cost per~~nine months ended September 30, 2016 and a corresponding credit to our "Proved developed and undeveloped ~~acre or the discounted cash flow models from our internally generated~~ oil and natural gas ~~reserves as~~properties" in our balance sheet related to the settlement of ~~September 30, 2015.~~litigation with a joint venture partner in the Eagle Ford shale. The ~~pricing utilized in~~fair market value of the properties transferred pursuant to the settlement was determined using a discounted cash flow ~~models was~~model of the estimated reserves. The estimated quantities of reserves utilized assumptions based on our internal geological, engineering and financial data. We utilized NYMEX ~~futures, adjusted for basis differentials. Our oil and natural gas properties were further discounted based~~forward strip prices to value the reserves, then applied various discount rates depending on the classification of ~~the underlying~~ reserves and ~~management's assessment of recoverability.~~other risk characteristics. The fair value measurements utilized ~~include~~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. ~~The average cost per undeveloped acre was based on recent comparable market transactions in each region.~~

9.~~Debt~~

~~Our total debt is summarized as follows:~~

(in thousands) September 30, 2015 December 31, 2014
EXCO Resources Credit Agreement $ 299,992
$ 202,492
2018 Notes 750,000
750,000
Unamortized discount on 2018 Notes (4,886 ) (5,957 )
2022 Notes 500,000
500,000
Total debt $ 1,545,106
$ 1,446,535

~~Terms and conditions of our debt obligations are discussed below.~~

~~EXCO Resources Credit Agreement~~

~~As of September 30, 2015, the EXCO Resources Credit Agreement had $300.0 million of outstanding indebtedness,~~ ~~$600.0 million~~ borrowing base and $293.4 million of unused borrowing base, net of letters of credit. The maturity date of the EXCO Resources Credit Agreement is July 31, 2018. The interest rate grid for the revolving commitment under the EXCO

~~Table of Contents~~

Resources Credit Agreement ranged from LIBOR plus 175 bps to 275 bps (or alternate base rate ("ABR") plus 75 bps to 175 bps), depending on our borrowing base usage. On September 30, 2015, the one month LIBOR was 0.2%, which resulted in an interest rate of approximately 2.5%.

~~As of~~ ~~September 30, 2015, we were in compliance with the financial covenants (each as defined in the EXCO Resources Credit Agreement), which required that we:~~

~~maintain a consolidated current ratio of at least~~ ~~1.0~~ ~~to 1.0 as of the end of any fiscal quarter;~~

~~maintain a ratio of consolidated EBITDAX to consolidated interest expense ("Interest Coverage Ratio") of at least 2.0 to 1.0 as of the end of any fiscal quarter; and~~

~~not permit a ratio of senior secured indebtedness to consolidated EBITDAX ("Secured Indebtedness Ratio") to be greater than 2.5 to 1.0 as of the end of any fiscal quarter.~~

On July 27, 2015, we amended the EXCO Resources Credit Agreement which decreased our borrowing base from $725.0 million to $600.0 million in connection with our semi-annual borrowing base redetermination. The amendment also included modifications to our financial covenants, interest rate grid and borrowing base if we issue certain indebtedness subordinated to the EXCO Resources Credit Agreement. On October 26, 2015, we closed a 12.5% senior secured second lien term loan with certain affiliates of Fairfax Financial Holdings Limited ("Fairfax") in the aggregate principal amount $300.0 million (“Fairfax Term Loan”) and a 12.5% senior secured second lien term loan with certain unsecured noteholders in the aggregate principal amount of $291.3 million (“Exchange Term Loan,” and together with the Fairfax Term Loan, “Second Lien Term Loans”). The proceeds from the Second Lien Term Loans were used to repay outstanding indebtedness under the EXCO Resources Credit Agreement and 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. See further discussion of the Second Lien Term Loans and the 2018 Notes and 2022 Notes repurchases below.

As a result of the Second Lien Term Loans, the interest rate grid under the EXCO Resources Credit Agreement was increased by 50 bps, the Interest Coverage Ratio was modified to require that we maintain a ratio of at least 1.25 to 1.00 as of the end of any fiscal quarter and the requirement to comply with the leverage ratio maintenance covenant (as defined in the EXCO Resources Credit Agreement) was terminated.

On October 19, 2015, we entered into an amendment to the EXCO Resources Credit Agreement that, among other things, reduced the borrowing base from $600.0 million to $375.0 million, effective upon the issuance of the Second Lien Term Loans. The amendment also amended the EXCO Resources Credit Agreement such that, upon our incurrence of second or third lien debt, including the Second Lien Term Loans, the revolving commitments under the EXCO Resources Credit Agreement were automatically reduced to $375.0 million. The Second Lien Term Loans limit the issuance of priority lien indebtedness to a maximum of $500.0 million without prior written consent of the administrative agent of the Fairfax Term Loan. In addition, the amendment provides that, with respect to the issuance of any second or third lien debt following the incurrence of the Second Lien Loans, if the issuance of such debt causes the aggregate principal amount of our second or third lien debt to exceed $900.0 million, the borrowing base will be further reduced.

The borrowing base under the EXCO Resources Credit Agreement remains subject to semi-annual review and redetermination by the lenders pursuant to the terms of the EXCO Resources Credit Agreement, and the next scheduled redetermination of the borrowing base is set to occur on or about March 1, 2016.

While we believe our existing capital resources, including our cash flow from operations and borrowing capacity under the EXCO Resources Credit Agreement are sufficient to conduct our operations through 2015 and 2016, there are certain risks arising from depressed oil and natural gas prices and declines in production volumes that could impact our ability to meet debt covenants in future periods. Our ability to maintain compliance with these covenants may be negatively impacted if oil and/or natural gas prices remain depressed for an extended period of time.

~~Second Lien Term Loans~~

On October 26, 2015, EXCO closed the Second Lien Term Loans. Each of the Second Lien Term Loans matures on October 26, 2020 and bears interest at a rate of 12.5% per annum, which is payable on the last day in each calendar quarter. The Second Lien Term Loans are guaranteed by substantially all of EXCO’s subsidiaries, with the exception of certain non-guarantor subsidiaries and our jointly-held equity investments with BG Group, and are secured by second-priority liens on substantially all of EXCO’s assets securing the indebtedness under the EXCO Resources Credit Agreement. The Second Lien Term Loans rank (i) junior to the debt under the EXCO Resources Credit Agreement and any other priority lien obligations, (ii) pari passu to one another and (iii) effectively senior to all of our existing and future unsecured senior indebtedness, including the 2018 Notes and the 2022 Notes, to the extent of the collateral.

~~Table of Contents~~

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

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

~~prepay, redeem or repurchase certain debt;~~

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

~~engage in asset sales or substantially alter the business that the we conduct;~~

~~enter into transactions with affiliates;~~

~~consolidate, merge or dispose of assets;~~

~~incur liens; and~~

~~enter into sale/leaseback transactions.~~

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

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

~~second lien debt in excess of $700.0 million;~~

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

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

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

second lien debt, other than the Exchange Term Loan, in excess of (i) $400.0 million prior to December 31, 2015 and(ii) an amount to be agreed upon with the administrative agent after December 31, 2015;

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

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

~~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.

~~As of~~ ~~September 30, 2015~~, ~~$750.0 million~~ ~~in principal was outstanding on the 2018 Notes. The unamortized discount on the 2018 Notes at~~ ~~September 30, 2015~~ ~~was $4.9 million. Interest accrues at~~ ~~7.5%~~ ~~per annum and is payable semi-annually in arrears on March 15 and September 15 of each year.~~

On October 26, 2015, EXCO repurchased an aggregate $375.9 million of the 2018 Notes in exchange for certain holders of the 2018 Notes to act as lenders under the Exchange Term Loan (“2018 Note Repurchase”). The 2018 Notes repurchased will be canceled by the trustee following customary settlement procedures. As a result of the 2018 Note Repurchase, the aggregate principal amount of outstanding 2018 Notes was reduced to $374.1 million. The 2018 Note Repurchase was funded with the proceeds from the Exchange Term Loan.

~~Table of Contents~~

~~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~~

As of September 30, 2015, $500.0 million in principal was outstanding on the 2022 Notes. The 2022 Notes were issued at 100.0% of the principal amount and bear interest at a rate of 8.5% per annum, payable in arrears on April 15 and October 15 of each year.

On October 26, 2015, EXCO repurchased $200.7 million of the 2022 Notes in exchange for certain holders of the 2022 Notes to act as lenders under the Exchange Term Loan (“2022 Repurchase,” and together with the 2018 Repurchase, the “Note Repurchase”). The 2022 Notes repurchased will be canceled by the trustee following customary settlement procedures. As a result of the 2022 Note Repurchase, the aggregate principal amount of outstanding 2022 Notes was reduced to $299.3 million. The 2022 Note Repurchase was funded with the proceeds from the Exchange Term Loan.

~~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 ~~$435.8~~$69.4 million for the nine months ended September 30, ~~2015.~~2016. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately ~~$1.3~~$1.4 billion ~~which~~that have fully offset our net deferred tax assets as of September 30, ~~2015.~~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 ~~the~~ three orand nine months ended September 30, ~~2015~~2016 or ~~2014.~~2015. OPCO may distribute any excess cash equally between us and BG Group when its operating cash flows are sufficient to meet its capital requirements. There are service agreements between us and OPCO whereby we provide administrative and technical services for which we are reimbursed. For the three and nine months ended September 30, ~~2015~~2016 and ~~2014,~~2015, these transactions included the following:

~~Table of Contents~~


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2015		2014		2015		2014		2016		2015		2016		2015
Amounts received from OPCO	$	7,281	$	24,660	$	23,847	$	45,631	$	3,824	$	7,281	$	12,586	$	23,847

As of September 30, ~~2015~~2016 and December 31, ~~2014,~~2015, the amounts owed were as follows:


(in thousands)	September 30, 2015		December 31, 2014		September 30, 2016		December 31, 2015
Amounts due to EXCO (1)	$	2,171	$	2,799	$	932	$	1,733
Amounts due from EXCO (1)	8,341		—		12,903		10,410


(1)	Advances to OPCO are recorded in "Other current assets" onin 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" onin our Condensed Consolidated Balance Sheets.

~~Services and investment agreement~~ESAS

On September 8, 2015, we closed the services and investment agreement with ~~Energy Strategic Advisory Services LLC ("ESAS"),~~ESAS, a ~~wholly-owned~~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. ~~See "Note 12. Services~~As part of the agreement, ESAS completed its required purchase of EXCO's common shares as of December 31, 2015 and ~~Investment Agreement" for further information.~~is currently the beneficial owner of approximately 6.5% of our outstanding common shares.

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

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

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

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

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

Fairfax

Hamblin Watsa Investment Counsel Ltd. (“Hamblin Watsa”), a wholly owned subsidiary of Fairfax, is the administrative agent of the Fairfax Term Loan and certain affiliates of Fairfax are lenders under the Fairfax Term Loan and a portion of the Exchange Term Loan. As of September 30, 2016, affiliates of Fairfax were the record holders of approximately $112.1 million in principal amount of the Exchange Term Loan. Samuel A. Mitchell, a member of ~~the~~ 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 ~~6.2%~~9.0% of our outstanding common shares. See “Note 9.8. Debt” for ~~further~~additional information.

~~12.Services and Investment Agreement~~

On March 31, 2015, we entered into a four year services and investment agreement with ESAS. As part of this agreement, ESAS provides us with certain strategic advisory services, including the development and execution of a strategic improvement plan.

On September 8, 2015, ESAS completed the purchase of 5,882,353 common shares from EXCO, par value $0.001 per share, at a price per share of $1.70, pursuant to the agreement. In addition, the services and investment agreement was amended to reduce the additional amount of common shares to at least $13.5 million that ESAS is obligated to purchase through open market purchases during the one year following the closing. ESAS will own common shares of EXCO with an aggregate cost basis of at least $23.5 million as of the first anniversary of the closing date, subject to certain extensions and exceptions.

As consideration for the services to be provided under the agreement, EXCO will pay ESAS a monthly fee of $300,000 and an annual incentive payment of up to $2.4 million per year that will be based on EXCO’s common share price achieving certain performance hurdles as compared to a peer group, provided that payment for the services will be held in escrow and contingent upon completion of the entire first year of services and required investment in EXCO. If EXCO’s performance rank is below the 50th percentile of the peer group, then the incentive payment will be zero. The incentive payment increases linearly from $1.0 million to $2.4 million as EXCO’s performance rank increases from the 50th to 75th percentile, as compared to the peer group. If EXCO’s performance rank is in the 75th percentile or above, then the incentive payment will be $2.4 million. For the three and nine months ended September 30, 2015, we did not recognize any expense for the annual incentive payment as a result of EXCO's performance rank.

As an additional performance incentive under the services and investment agreement, EXCO issued warrants to ESAS in four tranches to purchase an aggregate of 80,000,000 common shares. The table below lists the number of common shares issuable upon exercise of the warrants at each exercise price and the term of the warrants.

~~Table of Contents~~

Number of shares issuable Exercise Price Term
15,000,000 $2.75 April 30, 2019
20,000,000 $4.00 March 31, 2020
20,000,000 $7.00 March 31, 2021
25,000,000 $10.00 March 31, 2021

The warrants will vest on March 31, 2019 and their exercisability is subject to EXCO’s common share price achieving certain performance hurdles as compared to the peer group. If EXCO’s performance rank is in the bottom half of the peer group, then the warrants will be forfeited and void. The number of the exercisable shares under the warrants increases linearly from 32,000,000 to 80,000,000 as EXCO’s performance rank increases from the 50th to 75th percentile, as compared to the peer group. If EXCO’s performance rank is in the 75th percentile or above, then all 80,000,000 warrants will be exercisable. The performance measurement period began on March 31, 2015 and will end on March 31, 2019. As of September 30, 2015, EXCO's performance rank during the measurement period was below the 50th percentile of the peer group.

Prior to March 31, 2019, if EXCO terminates the agreement for any reason other than for cause (as defined in the agreement), or ESAS terminates the agreement for cause (as defined in the agreement), then all of the warrants will fully vest and become exercisable. Prior to March 31, 2019, if ESAS terminates the agreement for any reason other than for cause, or EXCO terminates the agreement for cause, then each of the warrants will be canceled and forfeited. On August 18, 2015, EXCO’s shareholders approved, among other things, the increase to the authorized number of common shares available for issuance to 780,000,000 which ensures that an adequate number of common shares are available for issuance, including the shares to be reserved for issuance under the warrants issued to ESAS.

~~In accordance with FASB ASC Topic 718,~~ ~~Compensation - Stock Compensation~~ ("ASC 718"), the grant date of the warrants was established upon approval of EXCO’s shareholders and the closing of the services and investment agreement which occurred on September 8, 2015. The fair value of the warrants is dependent on factors such as our share price, historical volatility, risk-free rate and performance relative to our peer group. The measurement of the warrants is accounted for in accordance with ASC Topic 505-50, ~~Equity-Based Payments to Non-Employees~~, which requires the warrants to be re-measured each interim reporting period until the completion of the services under the agreement. For the three and nine months ended September 30, 2015, we recognized equity-based compensation related to the warrants of $0.2 million.

13.Condensed consolidating financial statements

As of September 30, ~~2015~~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. On October 26, 2015, we closed~~Notes and the agreements governing the Second Lien Term ~~Loans which are guaranteed by the same subsidiaries as the EXCO Resources Credit Agreement and the 2018 Notes and 2022 Notes.~~Loans. All of our ~~non-guarantor subsidiaries were considered~~ unrestricted subsidiaries under the Second Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes ~~with the exception of our equity investment in OPCO.~~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 ~~subsequently~~ 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.

~~Table of Contents~~

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

September 30, ~~2015~~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	$	34,990		$	(14,479	)	$	—	$	—		$	20,511		$	9,754		$	(6,220	)	$	—	$	—		$	3,534
Restricted cash	1,500			19,954			—		—			21,454			—			18,434			—		—			18,434
Other current assets	66,089			97,428			—		—			163,517			13,233			75,608			—		—			88,841
Total current assets	102,579			102,903			—		—			205,482			22,987			87,822			—		—			110,809
Equity investments	—			—			55,036		—			55,036			—			—			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	—			119,046			—		—			119,046			—			93,511			—		—			93,511
Proved developed and undeveloped oil and natural gas properties	330,776			2,903,601			—		—			3,234,377			331,326			2,615,315			—		—			2,946,641
Accumulated depletion	(330,776		)	(2,258,194		)	—		—			(2,588,970		)	(330,776		)	(2,359,835		)	—		—			(2,690,611		)
Oil and natural gas properties, net	—			764,453			—		—			764,453			550			348,991			—		—			349,541
Other property and equipment, net	718			27,084			—		—			27,802			608			23,450			—		—			24,058
Investments in and advances to affiliates, net	832,810			—			—		(832,810		)	—			452,896			—			—		(452,896		)	—
Deferred financing costs, net	24,670			—			—		—			24,670			5,000			—			—		—			5,000
Derivative financial instruments	9,007			—			—		—			9,007			1,455			—			—		—			1,455
Goodwill	13,293			149,862			—		—			163,155			13,293			149,862			—		—			163,155
Deferred income taxes	18,749			—			—		—			18,749
Total assets	$	1,001,826		$	1,044,302		$	55,036	$	(832,810	)	$	1,268,354		$	496,789		$	610,125		$	31,973	$	(452,896	)	$	685,991
Liabilities and shareholders' equity
Current liabilities	$	56,967		$	228,293		$	—	$	—		$	285,260		$	74,818		$	167,105		$	—	$	—		$	241,923
Long-term debt	1,545,106			—			—		—			1,545,106			1,256,068			—			—		—			1,256,068
Other long-term liabilities	229			38,235			—		—			38,464			3,493			22,097			—		—			25,590
Payable to parent	—			2,240,498			—		(2,240,498		)	—			—			2,360,227			—		(2,360,227		)	—
Total shareholders' equity	(600,476		)	(1,462,724		)	55,036		1,407,688			(600,476		)	(837,590		)	(1,939,304		)	31,973		1,907,331			(837,590		)
Total liabilities and shareholders' equity	$	1,001,826		$	1,044,302		$	55,036	$	(832,810	)	$	1,268,354		$	496,789		$	610,125		$	31,973	$	(452,896	)	$	685,991

~~Table of Contents~~

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, ~~2014~~2015


(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	$	86,837		$	(40,532	)	$	—	$	—		$	46,305		$	34,296		$	(22,049	)	$	—	$	—		$	12,247
Restricted cash	—			23,970			—		—			23,970			2,100			19,120			—		—			21,220
Other current assets	110,145			150,346			—		—			260,491			51,133			65,201			—		—			116,334
Total current assets	196,982			133,784			—		—			330,766			87,529			62,272			—		—			149,801
Equity investments	—			—			55,985		—			55,985			—			—			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	—			276,025			—		—			276,025			—			115,377			—		—			115,377
Proved developed and undeveloped oil and natural gas properties	335,838			3,516,235			—		—			3,852,073			330,775			2,739,655			—		—			3,070,430
Accumulated depletion	(330,771		)	(2,083,690		)	—		—			(2,414,461		)	(330,775		)	(2,296,988		)	—		—			(2,627,763		)
Oil and natural gas properties, net	5,067			1,708,570			—		—			1,713,637			—			558,044			—		—			558,044
Other property and equipment, net	1,269			23,375			—		—			24,644			749			27,063			—		—			27,812
Investments in and advances to affiliates, net	1,746,931			—			—		(1,746,931		)	—			616,940			—			—		(616,940		)	—
Deferred financing costs, net	30,636			—			—		—			30,636			8,408			—			—		—			8,408
Derivative financial instruments	2,138			—			—		—			2,138			6,109			—			—		—			6,109
Goodwill	13,293			149,862			—		—			163,155			13,293			149,862			—		—			163,155
Deferred income taxes	35,935			—			—		—			35,935
Total assets	$	2,032,251		$	2,015,591		$	55,985	$	(1,746,931	)	$	2,356,896		$	733,028		$	797,241		$	40,797	$	(616,940	)	$	954,126
Liabilities and shareholders' equity
Current liabilities	$	75,441		$	289,930		$	—	$	—		$	365,371		$	74,472		$	178,447		$	—	$	—		$	252,919
Long-term debt	1,446,535			—			—		—			1,446,535			1,320,279			—			—		—			1,320,279
Other long-term liabilities	271			34,715			—		—			34,986			600			42,651			—		—			43,251
Payable to parent	—			2,058,683			—		(2,058,683		)	—			—			2,276,594			—		(2,276,594		)	—
Total shareholders' equity	510,004			(367,737		)	55,985		311,752			510,004			(662,323		)	(1,700,451		)	40,797		1,659,654			(662,323		)
Total liabilities and shareholders' equity	$	2,032,251		$	2,015,591		$	55,985	$	(1,746,931	)	$	2,356,896		$	733,028		$	797,241		$	40,797	$	(616,940	)	$	954,126

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended September 30, 2016



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

~~Table of Contents~~

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended 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	$	—		$	83,526		$	—		$	—	$	83,526		$	—		$	83,744		$	—		$	—	$	83,744
Purchased natural gas and marketing															—			6,773			—			—		6,773
Total revenues															—			90,517			—			—		90,517
Costs and expenses:
Oil and natural gas production	7			18,606			—			—		18,613			7			18,606			—			—		18,613
Gathering and transportation	—			23,743			—			—		23,743			—			23,743			—			—		23,743
Purchased natural gas															—			6,991			—			—		6,991
Depletion, depreciation and amortization	229			51,784			—			—		52,013			229			51,784			—			—		52,013
Impairment of oil and natural gas properties	1,372			338,021			—			—		339,393			1,372			338,021			—			—		339,393
Accretion of discount on asset retirement obligations	—			574			—			—		574			—			574			—			—		574
General and administrative	(2,345		)	15,738			—			—		13,393			(2,345		)	15,738			—			—		13,393
Other operating items	(3		)	(225		)	—			—		(228		)	(3		)	(225		)	—			—		(228		)
Total costs and expenses	(740		)	448,241			—			—		447,501			(740		)	455,232			—			—		454,492
Operating income (loss)	740			(364,715		)	—			—		(363,975		)	740			(364,715		)	—			—		(363,975		)
Other income (expense):
Interest expense, net	(27,761		)	—			—			—		(27,761		)	(27,761		)	—			—			—		(27,761		)
Gain on derivative financial instruments	37,348			—			—			—		37,348			37,348			—			—			—		37,348
Other income	14			7			—			—		21			14			7			—			—		21
Equity loss	—			—			(152		)	—		(152		)	—			—			(152		)	—		(152		)
Net loss from consolidated subsidiaries	(364,860		)	—			—			364,860		—			(364,860		)	—			—			364,860		—
Total other income (expense)	(355,259		)	7			(152		)	364,860		9,456			(355,259		)	7			(152		)	364,860		9,456
Loss before income taxes	(354,519		)	(364,708		)	(152		)	364,860		(354,519		)	(354,519		)	(364,708		)	(152		)	364,860		(354,519		)
Income tax expense	—			—			—			—		—			—			—			—			—		—
Net loss	$	(354,519	)	$	(364,708	)	$	(152	)	$	364,860	$	(354,519	)	$	(354,519	)	$	(364,708	)	$	(152	)	$	364,860	$	(354,519	)

~~Table of Contents~~

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the ~~three~~nine months ended September 30, ~~2014~~2016


(in thousands)	Resources			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated			Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	173		$	138,983	$	11,886		$	—		$	151,042		$	—		$	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	(31		)	16,823		5,285			—			22,077			4			39,139			—			—		39,143
Gathering and transportation	1			24,697		1,124			—			25,822			—			79,828			—			—		79,828
Purchased natural gas															—			17,273			—			—		17,273
Depletion, depreciation and amortization	658			59,392		4,863			—			64,913			298			63,697			—			—		63,995
Impairment of oil and natural gas properties															838			159,975			—			—		160,813
Accretion of discount on asset retirement obligations	4			532		173			—			709			—			2,006			—			—		2,006
General and administrative	(3,059		)	16,211		907			—			14,059			(6,062		)	44,688			—			—		38,626
Other operating items	(103		)	779		(13		)	—			663			(406		)	24,342			—			—		23,936
Total costs and expenses	(2,530		)	118,434		12,339			—			128,243			(5,328		)	430,948			—			—		425,620
Operating income (loss)	2,703			20,549		(453		)	—			22,799			5,328			(238,881		)	—			—		(233,553		)
Other income (expense):
Interest expense, net	(23,300		)	—		(674		)	—			(23,974		)	(54,186		)	—			—			—		(54,186		)
Gain on derivative financial instruments	40,835			—		2,009			—			42,844
Loss on derivative financial instruments															(11,632		)	—			—			—		(11,632		)
Gain on extinguishment of debt															119,374			—			—			—		119,374
Other income	31			16		6			—			53			9			28			—			—		37
Equity loss	—			—		(153		)	—			(153		)	—			—			(8,824		)	—		(8,824		)
Net income from consolidated subsidiaries	21,300			—		—			(21,300		)	—
Total other income	38,866			16		1,188			(21,300		)	18,770
Income before income taxes	41,569			20,565		735			(21,300		)	41,569
Net loss from consolidated subsidiaries															(247,677		)	—			—			247,677		—
Total other income (expense)															(194,112		)	28			(8,824		)	247,677		44,769
Loss before income taxes															(188,784		)	(238,853		)	(8,824		)	247,677		(188,784		)
Income tax expense	—			—		—			—			—			1,775			—			—			—		1,775
Net income	$	41,569		$	20,565	$	735		$	(21,300	)	$	41,569
Net loss															$	(190,559	)	$	(238,853	)	$	(8,824	)	$	247,677	$	(190,559	)

~~Table of Contents~~

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months ended 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		$	263,584		$	—		$	—	$	263,588		$	4		$	264,143		$	—		$	—	$	264,147
Purchased natural gas and marketing															—			21,012			—			—		21,012
Total revenues															4			285,155			—			—		285,159
Costs and expenses:
Oil and natural gas production	30			58,123			—			—		58,153			30			58,123			—			—		58,153
Gathering and transportation	—			74,243			—			—		74,243			—			74,243			—			—		74,243
Purchased natural gas															—			21,571			—			—		21,571
Depletion, depreciation and amortization	753			175,407			—			—		176,160			753			175,407			—			—		176,160
Impairment of oil and natural gas properties	8,263			1,001,784			—			—		1,010,047			8,263			1,001,784			—			—		1,010,047
Accretion of discount on asset retirement obligations	4			1,694			��			—		1,698			4			1,694			—			—		1,698
General and administrative	(6,569		)	47,796			—			—		41,227			(6,569		)	47,796			—			—		41,227
Other operating items	2,065			(947		)	—			—		1,118			2,065			(947		)	—			—		1,118
Total costs and expenses	4,546			1,358,100			—			—		1,362,646			4,546			1,379,671			—			—		1,384,217
Operating loss	(4,542		)	(1,094,516		)	—			—		(1,099,058		)	(4,542		)	(1,094,516		)	—			—		(1,099,058		)
Other income (expense):
Interest expense, net	(80,822		)	—			—			—		(80,822		)	(80,822		)	—			—			—		(80,822		)
Gain on derivative financial instruments	54,427			—			—			—		54,427			54,427			—			—			—		54,427
Other income	87			32			—			—		119			87			32			—			—		119
Equity loss	—			—			(1,452		)	—		(1,452		)	—			—			(1,452		)	—		(1,452		)
Net loss from consolidated subsidiaries	(1,095,936		)	—			—			1,095,936		—			(1,095,936		)	—			—			1,095,936		—
Total other income (expense)	(1,122,244		)	32			(1,452		)	1,095,936		(27,728		)	(1,122,244		)	32			(1,452		)	1,095,936		(27,728		)
Loss before income taxes	(1,126,786		)	(1,094,484		)	(1,452		)	1,095,936		(1,126,786		)	(1,126,786		)	(1,094,484		)	(1,452		)	1,095,936		(1,126,786		)
Income tax expense	—			—			—			—		—			—			—			—			—		—
Net loss	$	(1,126,786	)	$	(1,094,484	)	$	(1,452	)	$	1,095,936	$	(1,126,786	)	$	(1,126,786	)	$	(1,094,484	)	$	(1,452	)	$	1,095,936	$	(1,126,786	)

~~Table of Contents~~

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF ~~OPERATIONS~~CASH FLOWS

(Unaudited)

For the nine months ended September 30, ~~2014~~2016

(in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated
Revenues:
Oil and natural gas $ 3,469
$ 490,839
$ 38,172
$ —
$ 532,480
Costs and expenses:
Oil and natural gas production 344
56,440
14,880
—
71,664
Gathering and transportation 1
73,045
3,427
—
76,473
Depletion, depreciation and amortization 2,542
184,899
14,000
—
201,441
Accretion of discount on asset retirement obligations 13
1,564
508
—
2,085
General and administrative (2,332 ) 51,006
2,227
—
50,901
Other operating items (119 ) 6,510
(9 ) —
6,382
Total costs and expenses 449
373,464
35,033
—
408,946
Operating income 3,020
117,375
3,139
—
123,534
Other income (expense):
Interest expense, net (68,096 ) —
(2,010 ) —
(70,106 )
Loss on derivative financial instruments (13,802 ) —
(1,094 ) —
(14,896 )
Other income (loss) 183
(21 ) 14
—
176
Equity income —
—
548
—
548
Net income from consolidated subsidiaries 117,951
—
—
(117,951 ) —
Total other income (expense) 36,236
(21 ) (2,542 ) (117,951 ) (84,278 )
Income before income taxes 39,256
117,354
597
(117,951 ) 39,256
Income tax expense —
—
—
—
—
Net income $ 39,256
$ 117,354
$ 597
$ (117,951 ) $ 39,256



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

~~Table of Contents~~

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months ended September 30, 2015

(in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated
Operating Activities:
Net cash provided by operating activities $ 27,860
$ 98,996
$ —
$ —
$ 126,856
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions (1,784 ) (275,532 )
—
(277,316 )
Proceeds from disposition of property and equipment 686
6,711
—
—
7,397
Restricted cash —
4,016
—
—
4,016
Net changes in advances to joint ventures —
8,594
—
—
8,594
Equity investments and other —
1,455
—
—
1,455
Advances/investments with affiliates (181,813 ) 181,813
—
—
—
Net cash used in investing activities (182,911 ) (72,943 ) —
—
(255,854 )
Financing Activities:
Borrowings under credit agreements 97,500
—
—
—
97,500
Proceeds from issuance of common shares, net 9,829
—
—
—
9,829
Payments of common share dividends (62 ) —
—
—
(62 )
Deferred financing costs and other (4,063 ) —
—
—
(4,063 )
Net cash provided by financing activities 103,204
—
—
—
103,204
Net increase (decrease) in cash (51,847 ) 26,053
—
—
(25,794 )
Cash at beginning of period 86,837
(40,532 ) —
—
46,305
Cash at end of period $ 34,990
$ (14,479 ) $ —
$ —
$ 20,511

~~Table of Contents~~

~~EXCO RESOURCES, INC.~~



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

~~CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS~~

~~(Unaudited)~~

~~For the nine months ended~~ ~~September 30, 2014~~

(in thousands) Resources Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated
Operating Activities:
Net cash provided by (used in) operating activities $ (68,876 ) $ 412,618
$ 14,623
$ —
$ 358,365
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions (1,996 ) (305,206 ) (3,521 ) —
(310,723 )
Proceeds from disposition of property and equipment 68,242
8,213
81
—
76,536
Restricted cash —
(1,389 ) —
—
(1,389 )
Net changes in advances to joint ventures —
(3,181 ) —
—
(3,181 )
Equity investments and other —
1,749
—
—
1,749
Distributions received from Compass 5,856
—
—
(5,856 ) —
Advances/investments with affiliates 100,228
(100,228 ) —
—
—
Net cash provided by (used) in investing activities 172,330
(400,042 ) (3,440 ) (5,856 ) (237,008 )
Financing Activities:
Borrowings under credit agreements 40,000
—
—
—
40,000
Repayments under credit agreements (879,874 ) —
(5,096 ) —
(884,970 )
Proceeds received from issuance of 2022 Notes 500,000
—
—
—
500,000
Proceeds from issuance of common shares, net 271,760
—
—
—
271,760
Payments of common share dividends (40,604 ) —
—
—
(40,604 )
Compass cash distribution —
—
(5,856 ) 5,856
—
Deferred financing costs and other (10,076 ) —
—
—
(10,076 )
Net cash provided by (used in) financing activities (118,794 ) —
(10,952 ) 5,856
(123,890 )
Net increase (decrease) in cash (15,340 ) 12,576
231
—
(2,533 )
Cash at beginning of period 81,840
(35,892 ) 4,535
—
50,483
Cash at end of period $ 66,500
$ (23,316 ) $ 4,766
$ —
$ 47,950

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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;

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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 ~~the~~our business strategies and other corporate actions, ~~developed in connection with EXCO's strategic improvement plan.~~including restructuring our balance sheet and gathering and transportation contracts; and

our ability to continue as a going concern.

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. We caution users of the financial statements not to place undue reliance on any forward-looking statements. When considering our forward-looking statements, keep in mind the cautionary statements in this Quarterly Report on Form 10-Q, and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, ~~2014,~~2015, filed with the Securities and Exchange Commission ("SEC") on ~~February 25,~~ March 2, 2016 ("2015 ~~as amended by Amendment No. 1 to the Annual Report on Form 10-K/A, filed with the SEC on April 10, 2015 ("2014~~ 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 ~~undeveloped acreage~~ acquisition ~~opportunities in Texas and Louisiana.~~opportunities. We plan to carry out this strategy by executing on a strategic ~~improvement~~ plan that incorporates the following ~~focus areas:~~three core objectives: (i) ~~liability management;~~restructuring the balance sheet to enhance our capital structure and extend structural liquidity; (ii) ~~operational performance;~~transforming EXCO into the lowest cost producer; and (iii) ~~capital deployment; (iv) risk management; (v) portfolio repositioning;~~optimizing and ~~(vi) performance management.~~repositioning our portfolio. We believe this strategy will allow us to create long-term value for our shareholders.

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

Recent developments

~~Second Lien Term Loans~~

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 ~~October 26, 2015,~~August 24, 2016, we ~~closed~~completed a 12.5% senior secured second lien term loan in the aggregate principal amount $300.0 million (“Fairfax Term Loan”) and a 12.5% senior secured second lien term loan in the aggregate principal amount of $291.3 million (“Exchange Term Loan,” and together with the Fairfax Term Loan, “Second Lien Term Loans”). Each of the Second Lien Term Loans matures on October 26, 2020 and bears interest at a rate of 12.5% per annum, which is payable on the last day in each calendar quarter. The proceeds from the Fairfax Term Loan were used to reduce thecash tender offer for our outstanding ~~indebtedness under the EXCO Resources Credit Agreement. Additionally, we used the proceeds from the Exchange Term Loan to repurchase $375.9 million of our 7.5%~~ senior unsecured notes ~~due September 15, 2018~~ ("~~2018 Notes"~~Tender Offer") ~~and $200.7~~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")~~. As a result~~ for an aggregate purchase price of ~~the repurchases, the aggregate principal amount of the outstanding 2018 Notes and 2022 Notes was reduced to $374.1 million and $299.3 million, respectively.~~$40.0 million. See "Note 9.8. Debt" in the Notes to our Condensed Consolidated Financial Statements for a more detailed discussion of ~~these transactions~~the Tender Offer. During the nine months ended September 30, 2016, through the Tender Offer and a series of open market purchases, we repurchased an aggregate of $26.4 million and $152.7 million in principal amount of our 7.5% senior unsecured notes due September 15, 2018 ("2018 Notes") and 2022 Notes, respectively, with an aggregate of $53.3 million in cash. These repurchases resulted in net gains on extinguishment of debt of $57.4 million and $119.4 million for the three and nine months ended 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

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 ~~description~~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 ~~Second Lien Term Loans.~~

~~Proposed reverse share split~~

~~On July 30, 2015, we received~~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 ~~notice from the NYSE that the average closing price~~portion of our ~~common shares over~~working interest to our joint venture partner upon commencing development of future locations, (iii) terminate the ~~prior 30 consecutive trading days was below $1.00 per share, and, as a result, the price per share~~area of mutual interest, which required either party acquiring an interest in non-producing acreage included in certain areas to provide notice of the common shares was below the minimum average closing price required to maintain listing on the NYSE. The notice stated that we have six months to regain compliance with the NYSE continued listing standards, or until January 30, 2016, or the NYSE would initiate procedures to suspend and delist the common shares. In order to regain compliance with the NYSE continued listing standards,

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on the last trading day in any calendar month, the common shares must have (i) a closing price of at least $1.00 per share and (ii) an average closing price of at least $1.00 per share over the 30 consecutive trading day period ending on the last trading day of such month.

If our shareholders approve the reverse share split and our Board of Directors decide to effect the reverse share split, it will reduce the total number of our issued and outstanding common shares, including shares held by the Company as treasury shares, and the number of common shares each of our shareholders owns will be reduced in proportionacquisition to the ~~reverse~~non-acquiring party and allowed the non-acquiring party to acquire a proportionate share ~~split ratio. The proposed reverse share split will affect all shareholders uniformly~~in such acquired interest, (iv) provide that EXCO transfer to its joint venture partner a portion of its interests in certain producing wells and ~~will not affect any shareholder's percentage ownership of the company. Our past~~certain undeveloped locations in South Texas, effective May 1, 2016 and ~~future earnings (losses) per share,~~(v) modify or eliminate certain other provisions. See "Note 9. Commitments and ~~any dividends paid on our common shares, will be proportionately adjusted if the reverse share split is effected.~~

~~EXCO Resources Credit Agreement amendments~~

On February 6, 2015, we amended our credit agreement ("EXCO Resources Credit Agreement") to include, among other things, a ratio of consolidated EBITDAX to consolidated interest expense ("Interest Coverage Ratio") and a ratio of senior secured indebtedness to consolidated EBITDAX ("Secured Indebtedness Ratio"). On July 27, 2015, EXCO Resources Credit Agreement was amended to include modifications to our financial covenants, interest rate grid and borrowing base if we issue certain indebtedness subordinated to the EXCO Resources Credit Agreement. On October 19, 2015, we amended the EXCO Resources Credit Agreement which, among other things, decreased our borrowing base to $375.0 million effective with the issuance of the Second Lien Term Loans. In addition, our interest rate grid increased by 50 bps, the Interest Coverage Ratio was modified to require that we maintain a ratio of at least 1.25 to 1.00 as of the end of any fiscal quarter and our leverage ratio (as defined in the EXCO Resources Credit Agreement) was terminated. The next scheduled borrowing base redetermination for the EXCO Resources Credit Agreement is set to occur on or about March 1, 2016. See "Note. 9. Debt"contingencies" in the Notes to our Condensed Consolidated Financial Statements for additional information.

Divestitures

We executed a ~~more detailed discussion.~~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.

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

On ~~March 31, 2015,~~May 6, 2016, we closed a sale of certain non-core undeveloped acreage in South Texas and our Board of Directors appointed Harold L. Hickey to the position of President and Chief Executive Officer of EXCO. Mr. Hickey previously served as EXCO's President and Chief Operating Officer since February 2013 and Chief Operating Officer since October 2005.

On April 17, 2015, our Board of Directors appointed Harold H. Jameson to the position of Chief Operating Officer of EXCO. Mr. Jameson most recently served as EXCO’s Vice President of Development and Production with primary responsibilities including the horizontal shale development drilling programsinterests in ~~the Haynesville, Eagle Ford and Marcellus assets. Mr. Jameson has served in a Vice President role at EXCO since March 2011.~~

~~Services and Investment Agreement~~

~~On March 31, 2015, we entered into a~~ four year services and investment agreement with Energy Strategic Advisory Services LLC ("ESAS"), a wholly-owned subsidiary of Bluescape Resources Company LLC (“Bluescape”). As part of this agreement, ESAS will provide certain strategic advisory services including the development and execution of a strategic improvement plan. On September 8, 2015, we entered into an amendment to the agreement and closed the transactions contemplated by the agreement. At the closing, C. John Wilder, Executive Chairman of Bluescape, was appointed as a member of our Board of Directors and as the Executive Chairman of the Board of Directors. Pursuant to the amended agreement:

~~ESAS purchased 5,882,353 common shares from EXCO at a price of $1.70 per share on September 8, 2015;~~

~~ESAS agreed to purchase additional common shares of EXCO through open market purchases such that ESAS will own common shares of EXCO with an aggregate cost basis of at least $23.5~~producing wells for $11.5 million, ~~as of the first anniversary of the closing date,~~ subject to ~~certain extensions and exceptions;~~customary post-closing purchase price adjustments.

~~EXCO agreed to pay ESAS a monthly fee of $300,000 for the term of the agreement;~~

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~~EXCO agreed to pay ESAS an annual incentive payment of up to $2.4 million per year based on the price of our common shares achieving certain performance hurdles as compared to a peer group; and~~

EXCO issued to ESAS warrants to purchase an aggregate of 80,000,000 common shares with exercise prices ranging from $2.75 to $10.00 per share. The warrants vest on March 31, 2019 and their exercisability is subject to EXCO’s common share price achieving certain performance hurdles as compared to the peer group. On August 18, 2015, EXCO’s shareholders approved, among other things, the increase to the authorized number of common shares available for issuance to 780,000,000 which ensures that an adequate number of common shares are available for issuance, including the shares to be reserved for issuance under the warrants issued to ESAS.

~~For a more detailed discussion of this agreement, see "Note. 12. Services and Investment Agreement"~~See "Note 3. Divestitures" in the Notes to our Condensed Consolidated Financial ~~Statements.~~Statements for additional information.

EXCO Resources Credit Agreement

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

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, ~~derivative financial instruments,~~derivatives, business combinations, ~~share-based~~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 ~~are~~were used. These policies and others are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in EXCO's ~~2014~~2015 Form 10-K.

Our results of operations

A summary of key financial data for the three and nine months ended September 30, ~~2015~~2016 and ~~2014~~2015 related to our results of operations is presented below:

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	Three Months Ended September 30,					Quarter to quarter change				Nine Months Ended September 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)	2015			2014					2015				2014				Period to period change			2016			2015				Quarter to quarter change			2016				2015				Period to period change
Production:						Quarter to quarter change
Oil (Mbbls)	635			537		98				1,733				1,709			24				391			635			(244		)		1,388				1,733			(345		)
Natural gas (Mmcf)	27,493			29,731		(2,238		)		84,257				94,203			(9,946		)		24,107			27,493			(3,386		)		71,926				84,257			(12,331		)
Total production (Mmcfe) (1)	31,303			32,953		(1,650		)		94,655				104,457			(9,802		)		26,453			31,303			(4,850		)		80,254				94,655			(14,401		)
Average daily production (Mmcfe)	340			358		(18		)		347				383			(36		)		288			340			(52		)		293				347			(54		)
Revenues before derivative financial instrument activities:
Oil	$	27,444		$	50,746	$	(23,302	)		$	79,872			$	159,131		$	(79,259	)		$	16,215		$	27,444		$	(11,229	)		$	49,688			$	79,872		$	(30,184	)
Natural gas	56,082			100,296		(44,214		)		183,716				373,349			(189,633		)		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	$	83,526		$	151,042	$	(67,516	)		$	263,588			$	532,480		$	(268,892	)		$	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	$	37,348		$	42,844	$	(5,496	)		$	54,427			$	(14,896	)	$	69,323			$	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)	$	43.22		$	94.50	$	(51.28	)		$	46.09			$	93.11		$	(47.02	)		$	41.47		$	43.22		$	(1.75	)		$	35.80			$	46.09		$	(10.29	)
Natural gas (per Mcf)	2.04			3.37		(1.33		)		2.18				3.96			(1.78		)		2.27			2.05			0.22				1.77				2.19			(0.42		)
Natural gas equivalent (per Mcfe)	2.67			4.58		(1.91		)		2.78				5.10			(2.32		)		2.68			2.68			—				2.20				2.79			(0.59		)
Costs and expenses:
Oil and natural gas operating costs	$	12,669		$	14,099	$	(1,430	)		$	41,745			$	48,713		$	(6,968	)		$	8,797		$	12,669		$	(3,872	)		$	25,835			$	41,745		$	(15,910	)
Production and ad valorem taxes	5,944			7,978		(2,034		)		16,408				22,951			(6,543		)		3,811			5,944			(2,133		)		13,308				16,408			(3,100		)
Gathering and transportation	23,743			25,822		(2,079		)		74,243				76,473			(2,230		)		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	51,494			63,566		(12,072		)		174,509				197,102			(22,593		)		15,528			51,494			(35,966		)		62,848				174,509			(111,661		)
Depreciation and amortization	519			1,347		(828		)		1,651				4,339			(2,688		)		382			519			(137		)		1,147				1,651			(504		)
General and administrative (2)	13,393			14,059		(666		)		41,227				50,901			(9,674		)		10,746			13,393			(2,647		)		38,626				41,227			(2,601		)
Interest expense, net	27,761			23,974		3,787				80,822				70,106			10,716				16,997			27,761			(10,764		)		54,186				80,822			(26,636		)
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.40		$	0.43	$	(0.03	)		$	0.44			$	0.47		$	(0.03	)		$	0.33		$	0.40		$	(0.07	)		$	0.32			$	0.44		$	(0.12	)
Production and ad valorem taxes	0.19			0.24		(0.05		)		0.17				0.22			(0.05		)		0.14			0.19			(0.05		)		0.17				0.17			—
Gathering and transportation	0.76			0.78		(0.02		)		0.78				0.73			0.05				1.06			0.76			0.30				0.99				0.78			0.21
Depletion	1.65			1.93		(0.28		)		1.84				1.89			(0.05		)		0.59			1.65			(1.06		)		0.78				1.84			(1.06		)
Depreciation and amortization	0.02			0.04		(0.02		)		0.02				0.04			(0.02		)		0.01			0.02			(0.01		)		0.01				0.02			(0.01		)
Net income (loss) (3)	$	(354,519	)	$	41,569	$	(396,088	)		$	(1,126,786	)		$	39,256		$	(1,166,042	)		$	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 ~~$0.9~~$1.4 million and ~~$1.1~~$0.9 million for the three months ended September 30, ~~2015~~2016 and ~~2014,~~2015, respectively, and ~~$4.0~~$14.6 million and ~~$4.4~~$4.0 million for the nine months ended September 30, ~~2015~~2016 and ~~2014,~~2015, respectively.

(3)

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

The following is a discussion of our financial condition and results of operations for the three and nine months ended September 30, ~~2015~~2016 and ~~2014~~2015. The comparability of our results of operations for the three and nine months ended September 30, ~~2015~~2016 and ~~2014~~2015 was affected by:

~~the sale of Compass Productions Partners, LP ("Compass") during the fourth quarter of 2014;~~

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;

~~Table of Contents~~

the impact of declining natural gas production volumes from our reduced ~~horizontal~~ drilling ~~activities in certain shale formations; and~~activities;

significant changes in our capital structure as a result of transactions in 2016 and 2015, including the ~~rights offering~~issuance of the Second Lien Term Loans and ~~related private placement~~repurchases and exchanges of our ~~common shares~~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 ("~~Rights Offering"~~ESAS") and legal and advisory fees incurred in connection with the ~~first quarter~~restructuring of ~~2014~~our balance sheet and ~~debt financing transactions~~gathering and firm transportation contracts; and

the reductions in ~~2014.~~

~~General~~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 generally prohibiting the export of U.S. crude oil;~~

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

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

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

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

the cost and availability of other competitive fuels;

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

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

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

the availability of refining capacity;

technological advances affecting oil and natural gas production and consumption;

weather conditions and natural disasters;

foreign and domestic government relations; and

overall domestic and global economic conditions.

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

Oil and natural gas production, revenues and prices

The following table presents our production, revenue and average sales prices for the three and nine months ended September 30, ~~2015~~2016 and ~~2014:~~2015:


	Three Months Ended September 30,																		Three Months Ended September 30,
	2015					2014					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	18,161	$	39,131	$	2.15	19,934	$	71,491	$	3.59	(1,773	)	$	(32,360	)	$	(1.44	)	14,633	$	34,856	$	2.38	18,161	$	39,349	$	2.17	(3,528	)	$	(4,493	)	$	0.21
East Texas	4,763	12,516		2.63		2,311	8,383		3.63		2,452		4,133			(1.00		)	6,312	16,424		2.60		4,763	12,516		2.63		1,549		3,908			(0.03		)
South Texas	4,064	25,450		6.26		3,241	45,829		14.14		823		(20,379		)	(7.88		)	2,517	14,953		5.94		4,064	25,450		6.26		(1,547	)	(10,497		)	(0.32		)
Appalachia	4,315	6,429		1.49		5,148	13,279		2.58		(833	)	(6,850		)	(1.09		)
Other	—	—		—		2,319	12,060		5.20		(2,319	)	(12,060		)	(5.20		)
Appalachia and other																			2,991	4,629		1.55		4,315	6,429		1.49		(1,324	)	(1,800		)	0.06
Total	31,303	$	83,526	$	2.67	32,953	$	151,042	$	4.58	(1,650	)	$	(67,516	)	$	(1.91	)	26,453	$	70,862	$	2.68	31,303	$	83,744	$	2.68	(4,850	)	$	(12,882	)	$	—

~~Table of Contents~~


	Nine Months Ended September 30,																		Nine Months Ended September 30,
	2015					2014					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	57,851	$	133,192	$	2.30	64,600	$	268,100	$	4.15	(6,749	)	$	(134,908	)	$	(1.85	)	41,639	$	76,044	$	1.83	57,851	$	133,751	$	2.31	(16,212	)	$	(57,707	)	$	(0.48	)
East Texas	12,465	33,603		2.70		6,243	26,252		4.21		6,222		7,351			(1.51		)	18,933	39,607		2.09		12,465	33,603		2.70		6,468		6,004			(0.61		)
South Texas	11,183	75,082		6.71		10,320	141,537		13.71		863		(66,455		)	(7.00		)	9,003	45,542		5.06		11,183	75,082		6.71		(2,180	)	(29,540		)	(1.65		)
Appalachia	13,154	21,707		1.65		16,273	54,952		3.38		(3,119	)	(33,245		)	(1.73		)
Other	2	4		2.00		7,021	41,639		5.93		(7,019	)	(41,635		)	(3.93		)
Appalachia and other																			10,679	15,539		1.46		13,156	21,711		1.65		(2,477	)	(6,172		)	(0.19		)
Total	94,655	$	263,588	$	2.78	104,457	$	532,480	$	5.10	(9,802	)	$	(268,892	)	$	(2.32	)	80,254	$	176,732	$	2.20	94,655	$	264,147	$	2.79	(14,401	)	$	(87,415	)	$	(0.59	)

Production for the three and nine months ended September 30, ~~2015~~2016 decreased by ~~1.7~~4.9 Bcfe, or 5%15%, and ~~9.8~~14.4 Bcfe, or 9%15%, respectively, as compared with the same periods in ~~2014.~~2015. Significant components of the changes in production were a result of:

~~decrease~~ddecreased production of ~~1.8~~3.5 Bcfe and ~~6.7~~16.2 Bcfe for the three and nine months ended September 30, ~~2015,~~2016, respectively, in the North Louisiana region, primarily due to production declines ~~in excess of~~partially offset by additional volumes from ~~recent wells turned-to-sales. We also implemented additional rate restrictions during~~ the ~~flowback of recent~~ wells turned-to-sales in ~~this region, which reduced~~ the ~~initial production but are expected to improve the long-term performance~~second and third quarters of ~~the wells.~~2016.

increased production of ~~2.5~~1.5 Bcfe and ~~6.2~~6.5 Bcfe for the three and nine months ended September 30, ~~2015,~~2016, respectively, in the East Texas region, primarily due to additional ~~development as we resumed our drilling program in this region during 2014 and this region has been the primary focus of our 2015 development program.~~volumes from wells turned-to-sales.

~~increased~~decreased production in the South Texas region of ~~0.8~~1.5 Bcfe and ~~0.9~~2.2 Bcfe for the three and nine months ended September 30, ~~2015,~~2016, respectively, primarily due to ~~additional volumes from recent~~production declines and the transfer of a portion of our interests in certain producing wells ~~turned-to-sales~~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 ~~Eagle Ford shale and Buda formation.~~Notes to our Condensed Consolidated Financial Statements.

decreased production of ~~0.8~~1.3 Bcfe and ~~3.1~~2.5 Bcfe for the three and nine months ended September 30, ~~2015,~~2016, respectively, in the Appalachia region as a result of production declines. Production for the nine months ended September 30, 2015 was impacted by higher downtime including a reduction of volumes of 0.3 Bcfe due to a pipeline disruption in Northeast Pennsylvania and 0.1 Bcfe for wells shut-in due to low natural gas prices.

~~decreased production in the Other~~ region primarily due to the sale of our ~~interest~~interests in ~~Compass~~shallow conventional assets located in Pennsylvania in July 2016 and production declines. In addition, we shut-in approximately 0.8 Bcfe of production due to low regional natural gas prices during the nine months ended September 30, 2016. The regional natural gas price differential significantly widened late in the third quarter of 2016 and into the fourth quarter of ~~2014.~~2016. As a result, we have shut-in production for certain Marcellus shale wells in the region until natural gas prices improve. As discussed in "Note 3. Divestitures" in the Notes to our Condensed Consolidated Financial Statements, on October 3, 2016, we closed a sale of our interests in shallow conventional assets located in West Virginia. As such, our production in the Appalachia region for the remainder of 2016 is expected to further decline.

Oil and natural gas revenues for the three months ended September 30, ~~2015~~2016 decreased by ~~$67.5~~$12.9 million, or ~~45%~~15%, as compared with the same period in ~~2014.~~2015. The decrease in revenues was primarily the result of a decrease in oil and natural gas ~~prices as well as decreased production.~~production partially offset by an increase in natural gas prices. The reduction in our development activities and suspension of drilling in certain regions will cause our production to continue to decline unless we increase our development program. Our average natural gas sales price ~~decreased 39%~~increased 11% to ~~$2.04~~$2.27 per Mcf for the three months ended September 30, 2016 from $2.05 per Mcf for the three months ended September 30, 2015, ~~from $3.37 per Mcf for the three months ended September 30, 2014,~~ 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 ~~54%~~4% to $41.47 per Bbl for the three months ended September 30, 2016 from $43.22 per Bbl for the three months ended September 30, 2015 ~~from $94.50 per Bbl for the three months ended~~ ~~September 30, 2014~~, primarily due to lower market prices. The impact of lower market prices was partially offset by improved differentials in the South Texas region as a result a renegotiated sales contract which resulted in a higher realized price for the related oil production.

Oil and natural gas revenues for the nine months ended September 30, ~~2015~~2016 decreased by ~~$268.9~~$87.4 million, or ~~50%~~33%, as compared with the same period in ~~2014.~~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 ~~45%~~19% to ~~$2.18~~$1.77 per Mcf for the nine months ended September 30, 2016 from $2.19 per Mcf for the nine months ended September 30, 2015, ~~from $3.96 per Mcf for the nine months ended September 30, 2014,~~ primarily due to lower market prices. The realized prices for natural gas during the nine months ended September 30, 2015 and 2014 were negatively impacted by wide differentials in Appalachia as a result of an oversupply of natural gas in the Northeast region. Our average sales price of oil per Bbl decreased ~~50%~~22% to $35.80 per Bbl for the nine months ended September 30, 2016 from $46.09 per Bbl for the nine months ended 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 ~~$93.11 per Bbl~~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, ~~2014,~~2016 decreased by $5.7 million, or 27%, as compared with the same period in 2015, primarily due to lower ~~market~~volumes sold and lower sales prices.

~~Table of Contents~~

Oil and natural gas operating costs

The following tables present our operating costs for the three and nine months ended September 30, ~~2015~~2016 and ~~2014:~~2015:


	Three Months Ended September 30,																					Three Months Ended September 30,
	2015						2014						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	$	3,386	$	252	$	3,638	$	3,619	$	856	$	4,475	$	(233	)	$	(604	)	$	(837	)	$	2,841	$	341	$	3,182	$	3,386	$	252	$	3,638	$	(545	)	$	89		$	(456	)
East Texas	967		238		1,205		758		112		870		209			126			335			1,482		23		1,505		967		238		1,205		515			(215		)	300
South Texas	3,814		944		4,758		825		49		874		2,989			895			3,884			2,937		—		2,937		3,814		944		4,758		(877		)	(944		)	(1,821		)
Appalachia	2,745		315		3,060		3,698		52		3,750		(953		)	263			(690		)
Other	8		—		8		3,637		493		4,130		(3,629		)	(493		)	(4,122		)
Appalachia and other																						1,131		42		1,173		2,753		315		3,068		(1,622		)	(273		)	(1,895		)
Total	$	10,920	$	1,749	$	12,669	$	12,537	$	1,562	$	14,099	$	(1,617	)	$	187		$	(1,430	)	$	8,391	$	406	$	8,797	$	10,920	$	1,749	$	12,669	$	(2,529	)	$	(1,343	)	$	(3,872	)

	Three Months Ended September 30,																					Three Months Ended September 30,
	2015						2014						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	$	0.19	$	0.01	$	0.20	$	0.18	$	0.04	$	0.22	$	0.01		$	(0.03	)	$	(0.02	)	$	0.19	$	0.02	$	0.21	$	0.19	$	0.01	$	0.20	$	—		$	0.01		$	0.01
East Texas	0.20		0.05		0.25		0.33		0.05		0.38		(0.13		)	—			(0.13		)	0.23		—		0.23		0.20		0.05		0.25		0.03			(0.05		)	(0.02		)
South Texas	0.94		0.23		1.17		0.25		0.02		0.27		0.69			0.21			0.90			1.17		—		1.17		0.94		0.23		1.17		0.23			(0.23		)	—
Appalachia	0.64		0.07		0.71		0.72		0.01		0.73		(0.08		)	0.06			(0.02		)
Other	—		—		—		1.57		0.21		1.78		(1.57		)	(0.21		)	(1.78		)
Appalachia and other																						0.38		0.01		0.39		0.64		0.07		0.71		(0.26		)	(0.06		)	(0.32		)
Total	$	0.35	$	0.05	$	0.40	$	0.38	$	0.05	$	0.43	$	(0.03	)	$	—		$	(0.03	)	$	0.32	$	0.01	$	0.33	$	0.35	$	0.05	$	0.40	$	(0.03	)	$	(0.04	)	$	(0.07	)


	Nine Months Ended September 30,																					Nine Months Ended September 30,
	2015						2014						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	$	9,814	$	2,637	$	12,451	$	11,108	$	3,186	$	14,294	$	(1,294	)	$	(549	)	$	(1,843	)	$	8,421	$	493	$	8,914	$	9,814	$	2,637	$	12,451	$	(1,393	)	$	(2,144	)	$	(3,537	)
East Texas	2,983		1,027		4,010		2,231		223		2,454		752			804			1,556			3,746		229		3,975		2,983		1,027		4,010		763			(798		)	(35		)
South Texas	14,647		1,756		16,403		9,274		347		9,621		5,373			1,409			6,782			8,506		246		8,752		14,647		1,756		16,403		(6,141		)	(1,510		)	(7,651		)
Appalachia	8,403		440		8,843		10,782		58		10,840		(2,379		)	382			(1,997		)
Other	38		—		38		9,928		1,576		11,504		(9,890		)	(1,576		)	(11,466		)
Appalachia and other																						4,152		42		4,194		8,441		440		8,881		(4,289		)	(398		)	(4,687		)
Total	$	35,885	$	5,860	$	41,745	$	43,323	$	5,390	$	48,713	$	(7,438	)	$	470		$	(6,968	)	$	24,825	$	1,010	$	25,835	$	35,885	$	5,860	$	41,745	$	(11,060	)	$	(4,850	)	$	(15,910	)

	Nine Months Ended September 30,																					Nine Months Ended September 30,
	2015						2014						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	$	0.17	$	0.05	$	0.22	$	0.17	$	0.05	$	0.22	$	—		$	—		$	—		$	0.20	$	0.01	$	0.21	$	0.17	$	0.05	$	0.22	$	0.03		$	(0.04	)	$	(0.01	)
East Texas	0.24		0.08		0.32		0.36		0.04		0.40		(0.12		)	0.04			(0.08		)	0.20		0.01		0.21		0.24		0.08		0.32		(0.04		)	(0.07		)	(0.11		)
South Texas	1.31		0.16		1.47		0.90		0.03		0.93		0.41			0.13			0.54			0.94		0.03		0.97		1.31		0.16		1.47		(0.37		)	(0.13		)	(0.50		)
Appalachia	0.64		0.03		0.67		0.66		—		0.66		(0.02		)	0.03			0.01
Other	19.00		—		19.00		1.41		0.22		1.63		17.59			(0.22		)	17.37
Appalachia and other																						0.39		—		0.39		0.64		0.03		0.67		(0.25		)	(0.03		)	(0.28		)
Total	$	0.38	$	0.06	$	0.44	$	0.41	$	0.06	$	0.47	$	(0.03	)	$	—		$	(0.03	)	$	0.31	$	0.01	$	0.32	$	0.38	$	0.06	$	0.44	$	(0.07	)	$	(0.05	)	$	(0.12	)

~~Table of Contents~~

Oil and natural gas operating costs for the three and nine months ended September 30, ~~2015~~2016 decreased by ~~$1.4~~$3.9 million, or ~~10%~~31%, and ~~$7.0~~$15.9 million, or ~~14%~~38%, respectively, as compared with the same periods in ~~2014.~~2015. The decreases were primarily due to cost reduction efforts, including significant reductions in labor costs, repair and maintenance costs, chemical treatment costs, workover activity and saltwater disposal costs. Reduced labor costs were primarily due to significant reductions in our

workforce in 2015 and 2016. We sold our conventional assets in Pennsylvania and West Virginia in July 2016 and October 2016, respectively, and further reduced our workforce in the region. As such, our labor costs decreased in the Appalachia region for the three months ended September 30, 2016 and are expected to continue to decrease ~~was~~during the remainder of 2016. The reduction in saltwater disposal costs is primarily due to the ~~sale~~renegotiation of ~~our interest in Compass in the fourth quarter of 2014~~contracts and cost reduction efforts in the North Louisiana and Appalachia regions. These decreases were partially offset by higher oil and natural gas operating costs in the East Texas and South Texas regions as a result of additional producing wells compared to prior periods. The decrease in oil and natural operating costs per Mcfe was primarily due to the sale of our interest in Compass which had a higher average cost per Mcfe compared to the average for the rest of our properties.more cost-efficient disposal methods.

Gathering and transportation

Gathering and transportation expenses for the three ~~and nine~~ months ended September 30, ~~2015~~ ~~decreased~~2016 increased by ~~$2.1~~$4.2 million, or 8%18%, ~~and $2.2 million, or 3%, respectively,~~ as compared with the same ~~periods~~period in ~~2014.~~2015. Gathering and transportation expenses for the nine months ended September 30, 2016 increased by $5.6 million, or 8%, as compared with the same period in 2015. The ~~decrease was~~increases were primarily due to ~~reduced rates on a renegotiated firm transportation contract~~gathering expenses in connection with taking our gas in-kind from certain third-party operated wells in the North Louisiana region, ~~sale of our interest~~and higher gathering costs on volumes from wells recently turned-to-sales in Compass and decreased production in Appalachia. These decreases were partially offset by additional expenses incurred as a result of a shortfall under a minimum volume commitment for gathering services in the East Texas and North ~~Louisiana regions.~~Louisiana. Gathering and transportation expenses were ~~$0.76~~$1.06 per Mcfe for the three months ended September 30, ~~2015~~2016 as compared to $0.76 per Mcfe for the same period in 2015. Gathering and transportation expenses for the nine months ended September 30, 2016 were $0.99 per Mcfe as compared to $0.78 per Mcfe for the same period ~~in 2014.~~2015. The ~~decrease was primarily due to increased production in the East Texas region. Gathering and transportation expenses~~increases were ~~$0.78 per Mcfe for the nine months ended September 30, 2015 as compared to $0.73 per Mcfe for the same period in 2014. The increase was~~ primarily due to lower volumes in relation to fixed costs under gathering and firm transportation contracts in the East Texas and North Louisiana regions.

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

Purchased natural gas expenses

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

Production and ad valorem taxes

The following table presents our production and ad valorem taxes on a percentage of revenue basis and per Mcfe basis for the three and nine months ended September 30, ~~2015~~2016 and ~~2014:~~2015:


	Three Months Ended September 30,													Three Months Ended September 30,
	2015							2014						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	$	2,431		6.2	%	$	0.13	$	2,455	3.4	%	$	0.12	$	1,627	4.7	%	$	0.11	$	2,431	6.2	%	$	0.13
East Texas	522			4.2	%	0.11		207		2.5	%	0.09		277		1.7	%	0.04		522		4.2	%	0.11
South Texas	2,592			10.2	%	0.64		3,667		8.0	%	1.13		1,626		10.9	%	0.65		2,592		10.2	%	0.64
Appalachia	399			6.2	%	0.09		524		3.9	%	0.10
Other	—			—	%	—		1,125		9.3	%	0.49
Appalachia and other														281		6.1	%	0.09		399		6.2	%	0.09
Total	$	5,944		7.1	%	$	0.19	$	7,978	5.3	%	$	0.24	$	3,811	5.4	%	$	0.14	$	5,944	7.1	%	$	0.19

	Nine Months Ended September 30,													Nine Months Ended September 30,
	2015							2014						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	$	7,393		5.6	%	$	0.13	$	6,746	2.5	%	$	0.10	$	5,909	7.8	%	$	0.14	$	7,393	5.5	%	$	0.13
East Texas	822			2.4	%	0.07		629		2.4	%	0.10		864		2.2	%	0.05		822		2.4	%	0.07
South Texas	7,299			9.7	%	0.65		10,128		7.2	%	0.98		5,903		13.0	%	0.66		7,299		9.7	%	0.65
Appalachia	902			4.2	%	0.07		1,728		3.1	%	0.11
Other	(8		)	N/M		N/M		3,720		8.9	%	0.53
Appalachia and other														632		4.1	%	0.06		894		4.1	%	0.07
Total	$	16,408		6.2	%	$	0.17	$	22,951	4.3	%	$	0.22	$	13,308	7.5	%	$	0.17	$	16,408	6.2	%	$	0.17

Production and ad valorem taxes for the three months ended September 30, ~~2015~~2016 decreased by ~~$2.0~~$2.1 million, or ~~25%~~36%, as compared with the same period in ~~2014.~~2015, primarily due to lower production volumes in South Texas and North Louisiana and lower severance tax rates in North Louisiana. Production and ad valorem taxes for the nine months ended September 30, ~~2015~~2016 decreased by ~~$6.5~~$3.1 million, or ~~29%~~19%, as compared ~~with~~to the same period in ~~2014.~~2015. The ~~decrease was~~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 in the rate per Mcfe was primarily due to the sale of our interest in Compass in the fourth quarter of 2014 which had higher average production and~~

~~Table of Contents~~

ad valorem taxes per Mcfe compared to the average for the rest of our properties. Also, the recent wells turned-to-sales in the East Texas region received severance tax exemptions which reduced the rate per Mcfe.

In our North Louisiana region, we currently receive severance tax holidays ~~on certain horizontal wells which~~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 ~~2014,~~2015, the state of Louisiana ~~increased~~decreased its severance tax rate for wells that do not receive exemptions from ~~$0.118 per Mcf~~$0.163 to ~~$0.163~~$0.158 per Mcf. In July ~~2015,~~2016, the effective severance tax rate decreased to ~~$0.158~~$0.098 per Mcf.

Depletion, depreciation and amortization

Depletion, ~~expense~~depreciation and amortization for the three months ended September 30, ~~2015~~2016 decreased ~~by $12.1 million, or 19%, as compared with~~from the same period in ~~2014~~2015 primarily due to a decrease in ~~production and the~~ depletion ~~rate.~~expense of $36.0 million, or 70%. On a per Mcfe basis, the depletion rate for the three months ended September 30, ~~2015~~2016 was ~~$1.65~~$0.59 per Mcfe, compared with ~~$1.93~~$1.65 per Mcfe in the same period in ~~2014.~~2015. Depletion, ~~expense~~depreciation and amortization for the nine months ended September 30, ~~2015~~2016 decreased ~~by $22.6 million, or 11%, as compared with~~from the same period in ~~2014~~2015 primarily due to a decrease in ~~production and the~~ depletion ~~rate.~~expense of $111.7 million, or 64%. On a per Mcfe basis, the depletion rate for the nine months ended September 30, ~~2015~~2016 was ~~$1.84~~$0.78 per Mcfe, compared with ~~$1.89~~$1.84 per Mcfe in the same period in ~~2014.~~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.

~~Depreciation and amortization costs for the three months ended~~ ~~September 30, 2015~~ decreased by $0.8 million, or 61%, as compared with the same period in 2014. Depreciation and amortization costs for the nine months ended September 30, 2015 decreased by $2.7 million, or 62%, as compared with the same period in 2014. The decrease was primarily due to lower depreciable assets as a result of the sale of our interest in Compass.

Impairment of oil and natural gas properties

~~For~~We did not record an impairment to our oil and natural gas properties for the three months ended September 30, 2016 and we recorded impairments of $160.8 million to our oil and natural gas properties for the nine months ended September 30, ~~2015, we~~2016. We recorded impairments to our proved oil and natural gas properties of $339.4 million and $1.0 billion ~~respectively,~~for the three and nine months ended September 30, 2015, respectively. The impairments were primarily due to the significant decline in oil and natural gas prices. The trailing twelve month reference prices at September 30, 2015 were $3.06 per Mmbtu for natural gas and $59.21 per Bbl of oil. For the three and nine months ended September 30, 2014, we did not record impairments to our oilOil and natural gas ~~properties. We~~prices are volatile and we may incur additional impairments ~~to our oil and natural gas properties in 2015~~during 2016 if future oil and natural gas prices ~~do not increase.~~result in a decrease in the trailing twelve-month reference prices compared to September 30, 2016. The possibility and amount of any future impairment is difficult to predict, and will depend, in part, upon future oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs.

If the simple average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended September 30, 2015 had been $2.67 per Mmbtu for natural gas and $50.37 per Bbl of oil while all other factors remained constant, our ceiling test limitation related to the net book value of our proved oil and natural gas properties would have been reduced by approximately $259 million. The aforementioned prices were calculated based on a 12-month simple average, which includes the oil and natural gas prices on the first day of the month for the 10 months ended October 2015 and the prices for October 2015 were held constant for the remaining two months. This reduction would have increased the impairment of our oil and natural gas properties pursuant to the ceiling test by approximately $259 million ~~on a pro forma basis.~~ The pro forma reduction in our ceiling test limitation is partially the result of a pro forma decrease in our proved undeveloped reserves of approximately 44%, which was primarily due to certain locations that would not be economical when using the pro forma prices. This calculation of the impact of lower commodity prices is prepared based on the presumption that all other inputs and assumptions are held constant with the exception of oil and natural gas prices. Therefore, this calculation strictly isolates the impact of commodity prices on our ceiling test limitation and proved reserves. The impact of price is only a single variable in the estimation of our proved reserves and other factors could have a significant impact on future reserves and the present value of future cash flows. The other factors that impact future estimates of proved reserves include, but are not limited to, extensions and discoveries, changes in costs, drilling results, revisions due to performance and other factors, changes in development plans and production. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods and this pro forma estimate should not be construed as indicative of our development plans or future results.

~~Table of Contents~~

General and administrative

The following table presents our general and administrative expenses for the three and nine months ended September 30, ~~2015~~2016 and ~~2014:~~2015:


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended September 30,									Nine Months Ended September 30,
(in thousands, except per unit rate)	2015			2014			Quarter to quarter change			2015			2014			Period to period change
(in thousands)																			2016			2015			Quarter to quarter change			2016			2015			Period to period change
General and administrative expenses:
Gross general and administrative expenses	$	22,935		$	28,031		$	(5,096	)	$	71,920		$	92,908		$	(20,988	)	$	14,863		$	21,083		$	(6,220	)	$	42,635		$	65,014		$	(22,379	)
Technical services and service agreement charges	(3,541		)	(6,365		)	2,824			(12,314		)	(19,148		)	6,834			(1,312		)	(3,541		)	2,229			(5,705		)	(12,314		)	6,609
Operator overhead reimbursements	(3,328		)	(3,628		)	300			(9,872		)	(10,461		)	589			(3,463		)	(3,328		)	(135		)	(10,339		)	(9,872		)	(467		)
Capitalized salaries and equity-based compensation	(2,673		)	(3,979		)	1,306			(8,507		)	(12,398		)	3,891
Capitalized salaries																			(759		)	(1,748		)	989			(2,523		)	(5,646		)	3,123
General and administrative expenses, excluding equity-based compensation																			9,329			12,466			(3,137		)	24,068			37,182			(13,114		)
Gross equity-based compensation																			1,642			1,852			(210		)	14,990			6,906			8,084
Capitalized equity-based compensation																			(225		)	(925		)	700			(432		)	(2,861		)	2,429
General and administrative expenses	$	13,393		$	14,059		$	(666	)	$	41,227		$	50,901		$	(9,674	)	$	10,746		$	13,393		$	(2,647	)	$	38,626		$	41,227		$	(2,601	)

General and administrative expenses for the three months ended September 30, 2016 decreased by $2.6 million, or 20%, compared with the same period in 2015. General and administrative expenses for the nine months ended September 30, ~~2015~~2016 decreased by ~~$0.7~~$2.6 million, or 5%6%, ~~and $9.7 million, or 19%, respectively,~~ compared with the same ~~periods~~period in ~~the prior year.~~2015. Significant components of the changes in general and administrative expenses were a result of:

decreased personnel costs of ~~$4.0~~$7.0 million and ~~$12.8~~$22.3 million for the three and nine months ended September 30, ~~2015,~~2016, respectively, ~~compared~~primarily due to ~~the same periods in the prior year. The decrease is primarily the result of~~ reductions in our workforce and employee benefits.

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

increased professional and legal fees of $2.6 million and $3.0 million for the ~~second quarter~~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 ~~2014 and the first quarter of 2015;~~these initiatives.

decreased various other gross general and administrative expenses of ~~$1.1~~$2.3 million and ~~$8.2~~$4.9 million for the three and nine months ended September 30, ~~2015, respectively, compared to the same periods in the prior year.~~2016, respectively. These decreases reflect our efforts to reduce our general and administrative costs ~~such as office expenses, professional fees, travel and software licenses;~~throughout the organization.

decreased technical services and service agreement recoveries of ~~$2.8~~$2.2 million and ~~$6.8~~$6.6 million for the three and nine months ended September 30, ~~2015, respectively, compared to the same periods in the prior year.~~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; and~~2015.

decreased capitalized salaries ~~and equity-based compensation expenses~~ of ~~$1.3~~$1.0 million and ~~$3.9~~$3.1 million for the three and nine months ended September 30, 2016, respectively, primarily as a result of reduced employee headcount.

increased equity-based compensation of $0.5 million and $10.5 million for the three and nine months ended September 30, 2016, respectively. These increases were primarily due to $0.7 million and $11.6 million of additional compensation expense related to the warrants issued to ESAS in 2015 for the three and nine months ended September 30, 2016, respectively, compared to the same periods in the prior year. ~~These decreases were primarily~~The fair value of the warrants is dependent on factors such as ~~a result of a reduction in employee headcount.~~

~~The services and investment agreement entered into with ESAS could materially impact~~ our ~~general and administrative expenses in future periods. The agreement will result in cash payments ranging from $3.6 million to $6.0 million on an annual basis based on EXCO’s common~~ share price, ~~achieving certain~~historical volatility, risk-free rate and performance ~~hurdles as compared~~relative to ~~the~~our peer group. ~~For both~~These factors, in aggregate, contributed to a significant increase in the ~~three~~fair value of the warrants and ~~nine months ended~~the related equity-based compensation expense at September 30, 2015, we did not recognize any expense for the annual incentive payment as a result of EXCO's performance rank. ESAS also received warrants to purchase 80,000,000 common shares that are subject to exercisability restrictions based on our common share price achieving certain performance hurdles as compared to the peer group. For the three and nine months ended September 30, 2015, we recognized equity-based compensation related to the warrants of $0.2 million.2016. The expense related to ~~the annual incentive payment and~~ warrants ~~will be~~is re-measured and adjusted each interim reporting period; therefore, our general and administrative expenses in future periods could be volatile based on the ~~performance~~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 ~~common share price and the common share prices of our peers.~~workforce.

Other operating items

Other operating items ~~was~~were a net gain of ~~$0.2~~$1.1 million ~~for the three months ended September 30, 2015 primarily due to income from surface acreage that we own in the South Texas region~~ and a net loss of ~~$1.1~~$23.9 million ~~for the nine months ended September 30, 2015 primarily due to various legal expenses and other assessments. Other operating items was a net loss of $0.7 million and $6.4 million~~ for the three and nine months ended September 30, ~~2014, respectively. The net losses~~2016 primarily due to the settlement of the litigation with our joint venture partner. See "Note 9. Commitments and Contingencies" in the Notes to our Condensed Consolidated Financial Statements for ~~both periods primarily consisted of legal expenses.~~additional information.

~~Table of Contents~~

Interest expense, net

The following table presents our interest expense, net for the three and nine months ended September 30, ~~2015~~2016 and ~~2014~~2015:


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended September 30,									Nine Months Ended September 30,
(in thousands)	2015			2014			Quarter to quarter change			2015			2014			Period to period change			2016			2015			Quarter to quarter change			2016			2015			Period to period change
Interest expense, net:
EXCO Resources Credit Agreement																			$	1,585		$	2,024		$	(439	)	$	3,890		$	5,672		$	(1,782	)
Fairfax Term Loan																			9,375			—			9,375			28,125			—			28,125
2018 Notes	$	14,426		$	14,399		$	27		$	43,259		$	43,179		$	80		2,571			14,426			(11,855		)	8,076			43,259			(35,183		)
2022 Notes	10,625			10,625			—			31,875			19,479			12,396			2,512			10,625			(8,113		)	10,819			31,875			(21,056		)
EXCO Resources Credit Agreement	2,024			1,607			417			5,672			14,628			(8,956		)
Compass Production Partners Credit Agreement	—			610			(610		)	—			1,820			(1,820		)
Amortization of deferred financing costs	3,745			1,854			1,891			10,012			6,117			3,895			2,184			3,745			(1,561		)	7,052			10,012			(2,960		)
Capitalized interest	(3,094		)	(5,155		)	2,061			(10,121		)	(15,410		)	5,289			(1,297		)	(3,094		)	1,797			(3,939		)	(10,121		)	6,182
Other	35			34			1			125			293			(168		)	67			35			32			163			125			38
Total interest expense, net	$	27,761		$	23,974		$	3,787		$	80,822		$	70,106		$	10,716		$	16,997		$	27,761		$	(10,764	)	$	54,186		$	80,822		$	(26,636	)

Interest expense, net for the three and nine months ended September 30, ~~2015 increased $3.8~~2016 decreased $10.8 million and $26.6 million, respectively, from the same ~~period~~periods in ~~2014. The increase in interest expense was~~2015. These decreases were primarily due to lower outstanding balances on the ~~acceleration of deferred financing costs of $2.0 million associated with the reduction~~2018 Notes and 2022 Notes from debt restructuring activities and note repurchases in ~~our borrowing base under the EXCO Resources Credit Agreement in July~~ 2015 and ~~a reduction~~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.~~properties and suspension of our drilling and development program in certain areas.

~~Interest expense, net for~~In the ~~nine months ended September 30,~~fourth quarter of 2015, ~~increased $10.7~~we closed a 12.5% senior secured second lien term loan with certain unsecured noteholders in the aggregate principal amount of $400.0 million ~~from~~(“Exchange Term Loan," and together with the ~~same period in 2014. The increase in interest expense was primarily due~~Fairfax Term Loan, the "Second Lien Term Loans") and used the proceeds to ~~higher average interest rates as~~repurchase a ~~result~~portion of the issuance of the 2022 Notes, the acceleration of deferred financing costs associated with the reduction in our borrowing base under the EXCO Resources Credit Agreement in February 2015 and July 2015 and a reduction in capitalized interest related to lower balances of unproved oil and natural gas properties. This was partially offset by the acceleration of the unamortized discount on the term loan under the EXCO Resources Credit Agreement upon repayment in April 2014 and reduction in interest expense related to the Compass Production Partners Credit Agreement as a result of the sale of our remaining interest in Compass.

~~The issuance of the Second Lien Term Loans in October 2015 and the use of proceeds reduced our total~~ outstanding indebtedness by $285.3 million; however, these transactions will increase the average interest rate on our outstanding indebtedness. As a result of these transactions, we expect our annual interest expense to increase by approximately $21.0 million, excluding the impact of capitalized interest and amortization of deferred financing costs and discount on debt issuance. The repurchase of the 2018 Notes and 2022 Notes atin 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 ~~discount~~troubled debt restructuring pursuant to FASB ASC 470-60, Troubled Debt Restructuring by Debtors. As such, all cash payments under the ~~par value that occurred~~terms of the Exchange Term Loan, whether designated as interest or as principal amount, reduce the carrying amount and no interest expense, in ~~the fourth quarter of 2015~~accordance with GAAP, is ~~expected to~~recognized. This will result in a ~~gain on~~significantly lower interest expense than the ~~extinguishment~~contractual interest payments throughout the term of ~~debt of approximately $270.0 million to $280.0 million.~~the Exchange Term Loan.

Derivative financial instruments

Our oil and natural gas derivative financial instruments resulted in a net ~~gain~~gains of ~~$37.3~~$8.2 million and ~~$42.8~~$37.3 million for the three months ended September 30, ~~2015~~2016 and ~~2014,~~2015, respectively. Our oil and natural gas derivative financial instruments resulted in a net ~~gain of $54.4 million and a net~~ loss of ~~$14.9~~$11.6 million for the nine months ended September 30, ~~2015~~2016 and ~~2014,~~a net gain of $54.4 million for the nine months ended 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.

~~Table of Contents~~

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


	Three Months Ended September 30,								Nine Months Ended September 30,								Three Months Ended September 30,							Nine Months Ended September 30,
Average realized pricing:	2015		2014			Quarter to quarter change			2015		2014			Period to period change			2016		2015		Quarter to quarter change			2016		2015		Period to period change
Natural gas (per Mcf):
Net price, excluding derivatives	$	2.04	$	3.37		$	(1.33	)	$	2.18	$	3.96		$	(1.78	)	$	2.27	$	2.05	$	0.22		$	1.77	$	2.19	$	(0.42	)
Cash receipts (payments) on derivatives	0.70		0.11			0.59			0.67		(0.28		)	0.95
Cash receipts on derivatives																	0.04		0.70		(0.66		)	0.34		0.67		(0.33		)
Net price, including derivatives	$	2.74	$	3.48		$	(0.74	)	$	2.85	$	3.68		$	(0.83	)	$	2.31	$	2.75	$	(0.44	)	$	2.11	$	2.86	$	(0.75	)
Oil (per Bbl):
Net price, excluding derivatives	$	43.22	$	94.50		$	(51.28	)	$	46.09	$	93.11		$	(47.02	)	$	41.47	$	43.22	$	(1.75	)	$	35.80	$	46.09	$	(10.29	)
Cash receipts (payments) on derivatives	19.97		(1.96		)	21.93			18.95		(3.67		)	22.62
Cash receipts on derivatives																	9.65		19.97		(10.32		)	9.93		18.95		(9.02		)
Net price, including derivatives	$	63.19	$	92.54		$	(29.35	)	$	65.04	$	89.44		$	(24.40	)	$	51.12	$	63.19	$	(12.07	)	$	45.73	$	65.04	$	(19.31	)
Natural gas equivalent (per Mcfe):
Net price, excluding derivatives	$	2.67	$	4.58		$	(1.91	)	$	2.78	$	5.10		$	(2.32	)	$	2.68	$	2.68	$	—		$	2.20	$	2.79	$	(0.59	)
Cash receipts (payments) on derivatives	1.02		0.07			0.95			0.94		(0.31		)	1.25
Cash receipts on derivatives																	0.18		1.02		(0.84		)	0.47		0.94		(0.47		)
Net price, including derivatives	$	3.69	$	4.65		$	(0.96	)	$	3.72	$	4.79		$	(1.07	)	$	2.86	$	3.70	$	(0.84	)	$	2.67	$	3.73	$	(1.06	)

Our total cash receipts for the three months ended September 30, ~~2015~~2016 were ~~$31.9~~$4.7 million, or ~~$1.02~~$0.18 per Mcfe, compared to cash receipts of ~~$2.3~~$31.9 million, or ~~$0.07~~$1.02 per Mcfe, for the three months ended September 30, ~~2014.~~2015. Our total cash receipts for the nine months ended September 30, ~~2015~~2016 were ~~$89.0~~$38.1 million, or ~~$0.94~~$0.47 per Mcfe, compared to cash ~~payments $32.2~~receipts of $89.0 million, or ~~$0.31~~$0.94 per Mcfe, for the nine months ended September 30, ~~2014.~~2015. The differences between the cash receipts during ~~2015~~2016 and ~~cash payments during 2014~~2015 were primarily due to lower volumes hedged and lower strike prices in the ~~significant decline~~current period.

Gain on extinguishment of debt

For the three and nine months ended September 30, 2016, we recorded net gains on extinguishment of debt of $57.4 million and $119.4 million, respectively. The net gain for the three months ended September 30, 2016 was primarily the result of the Tender Offer in ~~oil~~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 $179.1 million in principal amount of the 2018 Notes and ~~natural gas prices. As noted above,~~2022 Notes with an aggregate of $53.3 million in cash through the ~~significant fluctuations between settlements on~~Tender Offer and open market repurchases. The net gains included an acceleration of the related deferred financings costs and notes discount, as well as direct costs associated with the transactions.

Equity loss

Our equity loss was $0.8 million and $0.2 million for the three months ended September 30, 2016 and 2015, respectively. Our equity loss was $8.8 million and $1.5 million for the nine months ended September 30, 2016 and 2015, respectively. The increase in our ~~derivative financial instruments demonstrate~~equity loss for the ~~volatility~~nine months ended September 30, 2016 from the same period in ~~commodity prices. We will continue~~2015 was primarily due to ~~evaluate plans~~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 ~~enter into additional derivative contracts based on market conditions.~~reduce future cash flows of our investment. In addition, we recorded a net loss of $2.8 million for the nine months ended 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 nine months ended September 30, ~~2015~~2016 and ~~2014~~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 September 30, ~~2015~~2016 was approximately ~~$1.3~~$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 nine months ended September 30, 2016, we had cancellation of debt income for tax purposes which reduced our net operating loss carryforwards ("NOLs") by $125.8 million.

The effective income tax rates, excluding the impact of the valuation allowances, would have been 38.3% and 38.1% for the three and nine months ended September 30, 2016, respectively, and 38.5% and 38.7% for the three and nine months ended September 30, 2015, ~~respectively, and 32.1% and 42.9% for the three and nine months ended September 30, 2014,~~ respectively. The effective tax rates, excluding the impact of the valuation allowance, differ from the statutory tax rates primarily due to permanent differences between the amounts recorded for financial reporting purposes and the amounts used for income tax purposes. During the three and nine months ended September 30, 2016, we recognized deferred income tax expense of $1.0 million and $1.8 million, respectively, related to a deferred tax liability for tax deductible goodwill. During the nine months ended September 30, 2016, the book basis of goodwill exceeded the tax basis that caused the previous book and tax basis differences to change from a deferred tax asset to a deferred tax liability. The deferred tax liability related to goodwill is considered to have an indefinite life based on the nature of the underlying asset and cannot be offset under GAAP with a deferred tax asset with a definite life, such as NOLs. However, the deferred income tax expense is not expected to result in cash payments of income taxes in the foreseeable future.

Our liquidity, capital resources and capital commitments

Overview

Our primary sources of capital resources and liquidity ~~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;

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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;~~commitments, as well as our ability to restructure these contracts;

potential acquisitions and/or dispositions of oil and natural gas properties or other ~~assets, including our ability to obtain financing in order to fund the acquisition of properties under a participation agreement with a joint venture partner in the Eagle Ford shale;~~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 ~~expected increase in our annual interest expense as a result of the issuance of~~quarterly payments related to the Second Lien Term Loans;

reductions to our borrowing base;

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

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

our ability to maintain compliance with debt ~~covenants.~~covenants; and

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

Recent events affecting liquidity

~~On February 6, 2015,~~In response to the low commodity price environment, we ~~amended~~have limited our development activities to preserve our capital resources and liquidity. The curtailment of the ~~financial covenants~~development of our properties will result in a decline in our production and reserves unless we increase our levels of development in the EXCO Resources Credit Agreement to include an Interest Coverage Ratio and Secured Indebtedness Ratio. On July 27, 2015, we amended the EXCO Resources Credit Agreement which decreased our borrowing base from $725.0 million to $600.0 million in connection with our semi-annual borrowing base redetermination. The amendment also included modifications to our financial covenants, interest rate grid and borrowing base if we issue certain indebtedness subordinated to the EXCO Resources Credit Agreement. On October 26, 2015, we closed the Fairfax Term Loan with an aggregate principal amount of $300.0 million and the Exchange Term Loan with an aggregate principal amount of $291.3 million for aggregate proceeds of $591.3 million. The fees and other expenses associated with the issuance of the Fairfax Term Loan and the Exchange Term Loan are estimated to be $15.0 million. The Second Lien Term Loans are due in October 2020 and accrue interest at a rate of 12.5% per annum. We utilized the proceeds from the Fairfax Term Loan to repay outstanding indebtedness under the EXCO Resources Credit Agreement, and the proceeds from the Exchange Term Loan to repurchase $375.9 million in principal of the 2018 Notes and $200.7 million in principal of the 2022 Notes.

On October 19, 2015, we amended the EXCO Resources Credit Agreement which, among other things, decreased our borrowing base to $375.0 million effective with the issuance of the Second Lien Term Loans. The next scheduled borrowing base redetermination for the EXCO Resources Credit Agreement is set to occur on or about March 1, 2016. See "Note 9. Debt" in the Notes to our Condensed Consolidated Financial Statements for a more detailed discussion. As a result of the issuance of the Second Lien Term Loans and the repayment of indebtedness under the EXCO Resources Credit Agreement, our unused borrowing base plus cash would have been $395.4 million on a pro forma basis if these transactions had occurred on September 30, 2015. Also, our consolidated net indebtedness would have been $270.3 million lower on a pro forma basis if these transactions had occurred on September 30, 2015.

future. Our ~~2015~~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. ~~The initiatives implemented during~~Since December 31, 2015, ~~have included~~we reduced the number of our general and administrative employees by approximately 26%, and reduced our field employees in the Appalachia region by 85% in conjunction with the sale of our conventional assets in Pennsylvania and West Virginia. We currently employ 191 persons as compared to 315 at December 31, 2015.

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

On September 1, 2016, the lenders under the EXCO Resources Credit Agreement postponed the scheduled redetermination of ~~commercial contracts including sales and firm transportation agreements.~~the borrowing base from September 1, 2016 to November 1, 2016 at our request. We are currently ~~evaluating transactions~~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 ~~could~~we will be able to amend the EXCO Resources Credit Agreement and our lenders have discretion in the timing and amount during the borrowing base redetermination process. In connection with the postponed redetermination, we may not request borrowings from the lenders under the EXCO Resources Credit Agreement that would result in their aggregate exposure to exceed $300.0 million, including letters of credit, until the effective date of the postponed redetermination.

During the three months ended September 30, 2016, we borrowed an additional $93.0 million under the EXCO Resources Credit Agreement primarily to fund the Tender Offer repurchases, interest payments and working capital. Our working capital requirements during the three months ended September 30, 2016 were negatively impacted by a significant customer modifying their method of credit assurance from a prepayment to a letter of credit. Furthermore, the limitation on the aggregate exposure within the EXCO Resources Credit Agreement in connection with the postponement of the redetermination process further ~~enhance~~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 plans to improve near-term liquidity ~~and capital structure including~~primarily include the issuance of additional indebtedness ~~restructure or repurchase~~and we are engaged in discussions with potential lenders. The availability and terms of ~~existing indebtedness, cost reductions~~this financing may be dependent upon our ability to reduce fixed commitments including gathering and ~~divestitures~~transportation contracts. We continue to negotiate a consensual restructuring of ~~assets. The Company currently has approximately $109 million~~gathering and transportation contracts with our counterparties. Our ability to execute these plans is conditioned upon factors including the availability of ~~additional second lien capacity under~~capital markets, market conditions, and the ~~Exchange Term Loan and approximately $125 million~~actions of third lien capacity. The Company is evaluating further opportunities to exchange outstanding unsecured notes for second or third lien term loans. In addition, we have taken preliminary actions to assess the potential market and valuation if we were to divest certain of our assets.counterparties. There is no assurance any such transactions will occur.

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The following table presents our liquidity and outstanding principal balance of debt as of September 30, ~~2015 and our pro forma liquidity as if the transactions resulting from the Second Lien Term Loans had occurred on September 30, 2015:~~2016:


(in thousands)	September 30, 2015		Pro Forma		September 30, 2016
EXCO Resources Credit Agreement	$	299,992	$	—	$	214,592
Second Lien Term Loans (1)	—		591,330
Exchange Term Loan (1)					400,000
Fairfax Term Loan					300,000
2018 Notes (2)	750,000		374,058		131,576
2022 Notes	500,000		299,269		70,169
Total debt	$	1,549,992	$	1,264,657
Total debt (3)					$	1,116,337
Net debt	$	1,508,027	$	1,237,684	$	1,094,369
Borrowing base	$	600,000	$	375,000
Unused borrowing base (3)	$	293,410	$	368,402
Cash (4)	$	41,965	$	26,973
Borrowing base (4)					$	300,000
Unused borrowing base (5)					$	75,372
Cash (6)					$	21,968
Unused borrowing base plus cash	$	335,375	$	395,375	$	97,340

(1)

~~The proceeds from~~Amount presented is the ~~Second Lien Term Loans were utilized~~outstanding principal balance and excludes $203.1 million of deferred reductions to ~~reduce indebtedness under~~carrying value. See "Note 8. Debt" in the ~~EXCO Resources Credit Agreement and repurchase $375.9 million in aggregate principal amount of the 2018~~ Notes ~~and $200.7 million in aggregate principal amount of the 2022 Notes.~~to our Condensed Consolidated Financial Statements for additional information.


(2)	Excludes unamortized discount of ~~$4.9~~$0.6 million ~~as of~~at September 30, ~~2015.~~2016.


(3)	~~Net~~Excludes unamortized deferred financing costs of ~~$6.6~~$12.8 million ~~in letters of credit as of~~at September 30, ~~2015. In connection with~~2016. Since September 30, 2016, we borrowed an additional $14.0 million under the ~~issuance of the Second Lien Term Loans in October 2015, the~~EXCO Resources Credit Agreement.

(4)

The borrowing base under the EXCO Resources Credit Agreement was ~~reduced~~$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 ~~$375.0 million.~~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.


~~(4)~~(5)	Net of $10.0 million in letters of credit at September 30, 2016.


(6)	Includes restricted cash of ~~$21.5~~$18.4 million ~~as of~~at September 30, ~~2015. The estimated fees and expenses of $15.0 million related to the Second Lien Term Loans reduced the cash balance on a pro forma basis as if the transactions had occurred on September 30, 2015.~~2016.

Credit agreements and long-term debt

As of September 30, ~~2015,~~2016, our consolidated debt consisted of the EXCO Resources Credit Agreement, ~~the~~ 2018 Notes, 2022 Notes and the ~~2022 Notes (see~~Second Lien Term Loans. See "Note 9.8. Debt" in the Notes to our Condensed Consolidated Financial Statements for a ~~further~~more detailed description of each ~~agreement).~~agreement.

As of September 30, ~~2015,~~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 ~~2.1~~1.1 to 1.0 exceeded the minimum of at least 1.0 to 1.0 as of the end of any fiscal ~~quarter;~~quarter. The consolidated current assets utilized in this ratio include unused commitments under the EXCO Resources Credit Agreement. As of September 30, 2016, the unused commitments were based on the Company's borrowing base of $325.0 million;

our ratio of consolidated EBITDAX to consolidated interest expense ("Interest Coverage ~~Ratio~~Ratio"), of ~~2.6~~1.6 to 1.0 exceeded the minimum of at least ~~2.0~~1.25 to 1.0 as of the end of any fiscal ~~quarter;~~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~~Ratio") of ~~1.1~~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

~~The issuance of~~

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

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

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

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

The EXCO Resources Credit Agreement and Second Lien Term Loans require our annual financial statements to include a report from our independent registered public accounting firm without an explanatory paragraph related to our ability to continue as a going concern. If the substantial doubt about our ability to continue as a going concern still exists at December 31, 2016 or if we fail to comply with the financial and other covenants in the EXCO Resources Credit ~~Agreement. The Interest Coverage Ratio was modified~~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 ~~require that we maintain a ratio~~our other outstanding indebtedness, including the 2018 Notes and 2022 Notes, which could adversely affect our business, financial condition and results of ~~at least 1.25 to 1.00 as of the end of any fiscal quarter and the leverage ratio requirement was eliminated.~~ operations.

The Second Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes contain incurrence covenants ~~which~~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. ~~Therefore, our~~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 9.8. Debt" in the Notes to our Condensed Consolidated Financial Statements.

There are certain risks arising from volatility in oil and/or natural gas prices that could restrict our liquidity or impact our ability to meet debt covenants in future periods. Furthermore, our liquidity and ability to meet debt covenants in future periodsCapital expenditures

Our 2016 capital budget of $85.0 million is ~~partially dependent~~focused on ~~our ability to offset natural production declines through the~~ development of our oil and natural gas properties. If we are not able to generate sufficient returns from the future development of our oil and natural gas properties, we may not undertake these projects and be able to adequately offset our natural production declines. The profitability of our future development projects is dependent on commodity prices, estimates of reserves, drilling and completion costs, operating

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costs, and other factors. Accordingly, our ability to effectively execute our corporate strategies and manage our operating, general and administrative expenses and capital expenditure programs is critical to our financial condition, liquidity and our results of operations.

Significant reductions in our borrowing capacity as a result of a redetermination of our borrowing base under the EXCO Resources Credit Agreement could have an impact on our capital resources and liquidity. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by further declines in oil and natural gas prices. Our ability to maintain compliance with debt covenants is negatively impacted when oil and/or natural gas prices and/or production declines over an extended period of time. In particular, our Interest Coverage Ratio and Secured Indebtedness Ratio, each as definedactivities in the ~~EXCO Resources Credit Agreement, are computed using EBITDAX for a trailing period.~~

~~In the event that our liquidity is not sufficient to fund our operating~~Haynesville and Bossier shales in North Louisiana and East Texas. The development activities included drilling 6 gross (5.2 net) wells and development program or we are not able to meet our debt covenants in future periods, we may attempt to refinance all or part of our existing debt, sell assets, incur additional indebtedness or raise equity. These alternatives may not be available on terms acceptable to us, which could adversely affect our business, financial condition and results of operations. Further, failing to comply with the financial and other restrictive covenantscompleting 14 gross (8.8 net) wells. We have flexibility in the ~~EXCO Resources Credit Agreement, Second Lien Term Loans, 2018 Notes or 2022 Notes could result in an event~~timing of ~~default, which could adversely affect~~development because our business, financial condition and results of operations. Also, we may be required to surrender certain assets pursuant to the security provisions of the EXCO Resources Credit Agreement and Second Lien Term Loans if we are not able to meet our debt covenants in future periods. See "Note 9. Debt" in the Notes to our Condensed Consolidated Financial Statements for a description of our covenants under the EXCO Resources Credit Agreement, Second Lien Term Loans, 2018 Notes and 2022 Notes.acreage is predominantly held-by-production.

~~Capital expenditures~~

For the nine months endedSeptember 30, ~~2015~~,2016, our capital expenditures totaled ~~$242.2~~$69.7 million, of which ~~$202.3~~$60.3 million was related to drilling and development activities. Our development program during the nine months ended September 30, 2015 included three operated drilling rigs focused primarily on the Haynesville and Bossier shales in the Shelby area of East Texas. Our development activities in North Louisiana during 2015 included limited drilling as well as completion activities in Caddo and DeSoto Parishes, Louisiana. Our development program in the South Texas region2016 included an average of one operated drilling rig focused on the ~~Eagle Ford~~Haynesville shale in North Louisiana. We concluded our

2016 drilling program in North Louisiana and ~~the Buda formation. Our capital expenditures~~turned-to-sales three additional wells in this region in the South Texas region also included the leasing of acreage in Zavala County, Texas. As a result of the decline in oil prices, we suspended our drilling in the South Texas region for the remainder of 2015. We drilled an appraisal well in the Marcellus shale in Northeast Pennsylvania which is expected to be turned-to-sales during the firstthird quarter of 2016. ~~In response~~Our two drilling rig contracts expire in 2017 and are currently being sub-leased to ~~the downturn~~another operator. Our development activities in ~~commodity prices, we have negotiated reductions in service costs with certain key vendors utilized in our drilling and~~East Texas included completion activities in the Haynesville and ~~continue to pursue further reductions.~~Bossier shales.

The following table presents our capital expenditures for the nine months ended September 30, ~~2015~~2016 and our forecasted capital expenditures for the remainder of 2015. Our capital program allocates a higher proportionate share of our expenditures towards the beginning of the year primarily as a result of completion activities related to wells that were in various stages of the development process at the end of 2014.2016.


	Nine Months Ended		October - December Forecast		Full Year Forecast		Nine Months Ended		October - December Forecast		Full Year Forecast
(in thousands)	September 30, 2015		2015		2015		June 30, 2016		2016		2016
Capital expenditures:
Development capital expenditures	$	202,277	$	37,723	$	240,000	$	60,285	$	2,215	$	62,500
Field operations, gathering and water pipelines	5,487		9,513		15,000
Lease purchases and seismic	10,859		7,141		18,000
Corporate and other	23,585		3,415		27,000
Other (1)							9,406		13,094		22,500
Total	$	242,208	$	57,792	$	300,000	$	69,691	$	15,309	$	85,000

~~Capital commitments~~

We have a participation agreement with a joint venture partner in our core area of the Eagle Ford shale to mitigate the impact of development expenditures on our capital resources and liquidity ("Participation Agreement"). The Participation Agreement requires us to offer to purchase our joint venture partner's interests in wells that have been on production for at least one year. The offers are made on a quarterly basis for a group of wells based on prices defined in the Participation Agreement, subject to specific well criteria and return hurdles. The wells included in the offer process that meet all of the specific well

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criteria are deemed to be "Committed Wells" and wells that do not meet the criteria are deemed to be "Uncertainty Wells." Our joint venture partner is required to accept our offers on Committed Wells if they meet the established return thresholds and may accept our offers on Uncertainty Wells.

As of September 30, 2015, we had spud 92 wells and turned-to-sales 87 wells since the inception of the Participation Agreement. The most recent well subject to the Participation Agreement was drilled in the first quarter of 2015 and our development plans do not include drilling any additional wells subject to the Participation Agreement during the remainder of 2015. There were 5 wells in various stages of development as of September 30, 2015 that will be turned-to-sales in future periods. The timing of these offers is dependent upon the date these wells are turned-to-sales, downtime during the year preceding the offer process and other factors. As of September 30, 2015, we had approximately 63 locations remaining to be drilled in the area under the Participation Agreement. The future development plans in this region are dependent on market conditions and operational decisions that impact the number of locations including spacing between wells, lateral lengths and other factors. Furthermore, any of the remaining locations that are not drilled prior to July 31, 2018 will not be subject to the offer process.

We received an extension on our third offer which will include a total of 24 gross (12.5 net) wells and is expected to be finalized in the fourth quarter of 2015. Our fourth offer is expected to occur in the fourth quarter of 2015, which will include a total of up to 23 gross (12.2 net) wells. This could include up to 11 gross (6.0 net) wells that were previously included in the third offer if our joint venture partner does not accept the preceding offer. The total purchase price of these offers will depend on our joint venture partner's acceptance as well as our joint venture partner's option to retain an undivided 15% of their collective interest in certain wells. If our joint venture partner accepts these offers, we expect the offer and acceptance process to be completed and the acquisition to close in the fourth quarter of 2015. The acquisitions of wells in connection with this agreement are expected to be funded with borrowings under the EXCO Resources Credit Agreement. This could have an impact on our liquidity and capital resources depending on the purchase price and the incremental borrowing capacity related to the acquired properties.

We currently estimate that 40 to 50 additional gross wells will qualify to be included in offers during 2016. However, the extent and timing of these acquisitions in future periods will be dependent on the terms and conditions of the offer process. The amounts for future acquisitions will depend on future reserves, commodity prices,(1) Other capital expenditures ~~production, revenues, expenses, as well as our joint venture partner's intentions to accept offers~~are comprised primarily of capitalized corporate costs, field operations and exercise their right to retain an interest. As such, it is not possible to reasonably estimate the amounts for future acquisitions under the agreement. If our offers for the wells included in the first four quarters of the offer process do not meet the established return thresholds, we must increase our offer to meet the thresholds or our joint venture partner will no longer be required to accept future offers for Committed Wells that meet the established return thresholds. However, we are required to continue to offer to purchase wells under the agreement and our joint venture partner will retain the ability to accept or decline our offer.land costs.

Historical sources and uses of funds

Our primary sources of cash for the nine months ended September 30, ~~2015~~2016 were cash flows from operations and borrowings under the EXCO Resources Credit Agreement.

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


	Nine Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2015			2014			2016			2015
Net cash provided by operating activities	$	126,856		$	358,365
Net cash provided by (used in) operating activities							$	(3,740	)	$	126,856
Net cash used in investing activities	(255,854		)	(237,008		)	(56,150		)	(255,854		)
Net cash provided by (used in) financing activities	103,204			(123,890		)
Net cash provided by financing activities							51,177			103,204
Net decrease in cash	$	(25,794	)	$	(2,533	)	$	(8,713	)	$	(25,794	)

Operating activities

The primary factors impacting our cash flows from operating activities ~~generally~~ 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.

~~Table of Contents~~

For the nine months ended September 30, ~~2015,~~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 $126.9 million as compared to $358.4 million~~ for the nine months ended September 30, ~~2014.~~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 ~~changes in accounts payable resulting from~~ lower ~~collections from advance billings to other working interest owners in the Eagle Ford shale as well as lower collections of revenues payable to other owners. The decrease was partially offset by~~ cash receipts ~~of $89.0 million~~ on derivative contracts of $38.1 million for the nine months ended September 30, ~~2015~~2016 compared to ~~cash payments of $32.2~~$89.0 million for the same period in 2015.

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

Financing activities

For the nine months ended September 30, ~~2014,~~2016, our net cash ~~used in investing~~provided by financing activities was ~~$237.0~~$51.2 million primarily due to ~~drilling and development activities~~$147.1 million in net borrowings under the ~~East Texas, North Louisiana and South Texas regions. This was~~EXCO Resources Credit Agreement partially offset by ~~approximately $68.2~~payments of $38.1 million on the Exchange Term Loan, which reduced its carrying value, and an aggregate of $53.3 million of ~~proceeds received from the sale~~cash payments used to repurchase a portion of our ~~interest in certain non-operated assets in~~2018 Notes and 2022 Notes. On March 29, 2016, we borrowed our remaining unused commitments of $232.4 million under the ~~Permian Basin.~~

~~Financing activities~~

EXCO Resources Credit Agreement to secure our liquidity. Prior to the completion of the borrowing base redetermination process on March 29, 2016, we repaid the entire $232.4 million. The borrowing and subsequent repayment both occurred on the same day. For the nine months ended September 30, 2015, our net cash provided by financing activities was $103.2 million primarily due to $97.5 million in borrowings under the EXCO Resources Credit Agreement and $9.8 million in net proceeds from the issuance of common shares to ESAS. ~~For the nine months ended September 30, 2014, our net cash used in financing activities was~~ ~~$123.9 million~~ ~~primarily due to~~ ~~$839.9 million~~ ~~in net payments of the outstanding borrowings under the EXCO Resources Credit Agreement,~~ ~~$40.6 million~~ ~~of dividend payments and $10.1 million of deferred financing costs primarily related to issuance of the 2022 Notes. This was partially offset by~~ ~~$500.0 million~~ ~~of gross proceeds received from issuance of the 2022 Notes and approximately $272.9 million of gross proceeds received from the Rights Offering.~~

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.

~~Table of Contents~~

Our derivative financial instruments are comprised of oil and natural gas swaps, ~~basis swaps, three-way~~ collars and ~~call option~~swaption contracts. As of September 30, ~~2015,~~2016, we had derivative financial instruments in place for the volumes and prices shown below:

(in thousands, except prices) NYMEX gas volume - Mmbtu Weighted average contract price per Mmbtu NYMEX oil volume - Bbls Weighted average contract price per Bbl
Swaps:
Remainder of 2015 12,650
$ 4.02
322
$ 86.44
2016 23,790
3.23
915
61.89
2017 10,950
3.28
—
—
2018 3,650
3.15
—
—
Basis swaps:
Remainder of 2015 —
—
23
6.10
Call options:
Remainder of 2015 5,060
4.29
92
100.00
Three-way collars:
Remainder of 2015 6,900
—

Sold call 4.47
—
Purchased put 3.83
—
Sold put 3.33
—
2016 10,980
—

Sold call 4.80
—
Purchased put 3.90
—
Sold put 3.40
—



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

We had derivative financial instruments that covered approximately ~~69%~~60% and ~~66%~~55% of production volumes during the three and nine months ended September 30, ~~2015,~~2016, respectively.

See further details on our derivative financial instruments in "Note 7. Derivative financial instruments" and "Note 8.10. Fair value measurements" in the Notes to our Condensed Consolidated Financial Statements.

Off-balance sheet arrangements

As of September 30, ~~2015~~2016, we had no arrangements or any guarantees of off-balance sheet debt to third parties.

Contractual obligations and commercial commitments

On ~~October 26, 2015,~~July 25, 2016, we ~~closed~~amended and restated the ~~Second Lien Term Loans and utilized the proceeds~~Participation Agreement to ~~repay indebtedness under the EXCO Resources Credit Agreement and repurchase~~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 ~~2018 Notes~~area of mutual interest, provide that we transfer to our joint venture partner a portion of our interests in certain producing wells and ~~the 2022 Notes.~~modify or eliminate other provisions. See "Note 9. ~~Debt"~~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, ~~2014.~~2015.

~~Table of Contents~~

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity price risk

Our objective in entering into derivative financial instruments is to manage our exposure to commodity price fluctuations, protect our returns on investments, and achieve a more predictable cash flow in connection with our financing activities and borrowings related to these activities. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if oil and natural gas prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instrument contracts. Cash losses or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration. Our credit rating and financial condition may restrict our ability to enter into certain types of derivative financial instruments and limit the maturity of the contracts with counterparties.

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

Our use of derivative financial instruments could have the effect of reducing our revenues and the value of our securities. For the nine months ended September 30, ~~2015,~~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 ~~$41.9~~$44.1 million for our oil and natural gas swap contracts. The ultimate settlement amount of our outstanding derivative financial instrument contracts is dependent on future commodity prices. We may incur significant unrealized losses in the future from our use of derivative financial instruments to the extent market prices increase and our derivatives contracts remain in place.

Interest rate risk

At September 30, ~~2015~~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 9.8. Debt" in the Notes to our Condensed Consolidated Financial

Statements. At September 30, ~~2015~~2016, we had approximately ~~$300.0~~$214.6 million in outstanding borrowings under the EXCO Resources Credit Agreement. A 1% increase in interest rates (100 bps) based on the variable borrowings as of September 30, ~~2015~~2016 would result in an increase in our interest expense of approximately ~~$3.0~~$2.1 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

Item 4. Controls and Procedures

Disclosure controls and procedures. Pursuant to Rule 13a-15(b) under the Exchange Act, EXCO's management has evaluated, under the supervision and with the participation of our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and principal financial officer have concluded that EXCO's disclosure controls and procedures were effective as of September 30, ~~2015~~2016 to ensure that information that is required to be disclosed by EXCO in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms and (ii) accumulated and communicated to EXCO's management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There were no changes in EXCO's internal control over financial reporting that occurred during the quarter ended September 30, ~~2015~~2016 that have materially affected, or are reasonably likely to materially affect, EXCO's internal control over financial reporting.

~~Table of Contents~~

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. We do not believe that any resulting liability from existing legal proceedings, individually or in~~us under the ~~aggregate, will have a material adverse effect on our results of operations or financial condition.~~agreements.


Item 1A.	Risk Factors

During the third quarter of ~~2015,~~2016, there were no material changes to the Risk Factors disclosed in our ~~2014~~2015 Form 10-K, except for the following:

IfThe 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 ~~fail~~may not be able to ~~comply with~~operate in the ~~continued listing standards of the NYSE, it may result in a delisting of our common shares from the NYSE.~~future.

~~Our common shares are currently and~~The unaudited Condensed Consolidated Financial Statements included herein have been ~~listed for trading~~prepared on a going concern basis, which contemplates the ~~NYSE,~~realization of assets and the ~~continued listing~~satisfaction of ~~our common shares on~~liabilities and other commitments in the ~~NYSE is subject~~normal course of business. Our liquidity and ability to ~~our compliance with a number of listing standards. To~~ maintain compliance with these continued listing standards, the Company is required to maintain an average closing price of $1.00 or more over a consecutive 30 trading-day period. On July 30, 2015, we received a notice from the NYSE that the average closing price of our common shares over the prior 30 consecutive trading days was below $1.00 per share, and, as a result, the price per share of the common shares was below the minimum average closing price required to maintain listing on the NYSE. The notice stated that we had six months to regain compliance with the NYSE continued listing standards, or until January 30, 2016, or the NYSE would initiate procedures to suspend and delist the common shares.

In September 2015, our Board of Directors authorized the calling of a Special Meeting of Shareholders to authorize the Board of Directors to effect a reverse share split at a ratio of up to 1-for-10 common shares. The decision to effect a reverse share split and the exact ratio of the reverse share split would be made by our Board of Directors in its sole discretion. If the Company effects the reverse share split, the common shares will be deemed to be in compliance if, promptly after the reverse share split, the price per common share exceeds $1.00 per share and remains above that level for at least the following 30 trading days. Implementation of the reverse share split is subject to the approval of the Company's shareholders which will be voted ondebt covenants have been negatively impacted by the Company's shareholders at the Special Meeting of Shareholders on November 16, 2015. The delisting of our common shares from the NYSE could result in even further reductions in our share price, would substantially limit the liquidity of our common shares, and materially adversely affect our ability to raise capital or pursue strategic restructuring, refinancing or other transactions on acceptable terms, or at all. Delisting from the NYSE could also have other negative results, including the potential loss of confidence by institutional investors.

~~We currently have negative shareholders’ equity, which could adversely affect our financial condition and otherwise adversely impact our business and growth prospects.~~

~~We have recently experienced losses as a result of the recent decline in~~prolonged depressed oil and natural gas ~~prices,~~price environment, levels of indebtedness, and asgathering, transportation and certain other commercial contracts. As of September 30, ~~2015,~~2016, we had ~~negative shareholders’ equity~~$3.5 million in cash and cash equivalents, $75.4 million of ~~$600 million, which means that~~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 ~~total liabilities exceeded~~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 ~~total assets. The continuing existence of negative shareholders’ equity may limit our ability to obtain future debt or equity financing or to pay future dividends or other distributions. If~~borrowing base, and we are unable to ~~obtain financing in~~predict the outcome of any future ~~it could have a negative effect on our operations and our liquidity.~~

The term loan agreements governing the Second Lien Term Loans contain restrictive covenants that substantially limit our ability to incur additional indebtedness, which may limit our future sources of financing and our ability to raise additional capital to fund our operations.

The term loan agreements governing the Second Lien Term Loans contain restrictive covenants that, among other things, substantially limit our ability to incur additional indebtedness. See further details on these covenants in "Note 9. Debt" in the Notes to our Condensed Consolidated Financial Statements. These restrictive covenants may materially impact our ability to finance our operations, fund our capital needs or obtain additional financing on acceptable terms or at all. As a result, we may be unable to obtain funding for, among other things, future acquisitions, operating activities, capital expenditures or debt service requirements, which would have a material impact on our business and financial condition. For additional information concerning restrictive covenants in the agreements governing our indebtedness, please see “Risk Factors-Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests” in the 2014 Form 10-K.

~~Table of Contents~~

~~As a result of the Fairfax Term Loan, there may be an actual or apparent conflict of interest between Hamblin Watsa and a member of our Board of Directors.~~

Hamblin Watsa, a wholly owned subsidiary of Fairfax, is the administrative agent of the Fairfax Term Loan. Samuel A. Mitchell, a member of our Board of Directors, is a Managing Director of Hamblin Watsa and a member of Hamblin Watsa’s investment committee, which consists of seven members that manage the investment portfolio of Fairfax. Additionally, based on filings with the Securities and Exchange Commission, Fairfax is the beneficial owner of approximately 6.2% of our outstanding common shares.redeterminations.

As ~~a result, there may~~of September 30, 2016, we were in compliance with the financial covenants under the EXCO Resources Credit Agreement. If we are not able to execute transactions to improve our financial condition, we do not believe we will be ~~an actual or apparent conflict of interest between Mr. Mitchell’s duties~~able to ~~our company and Mr. Mitchell’s duties to Hamblin Watsa, including, among other things,~~comply with ~~respect to the fairness~~all of the ~~terms~~covenants under the EXCO Resources Credit Agreement or have sufficient liquidity to conduct our business operations based on existing conditions and estimates during the next twelve months. If we become insolvent, investors in our common shares may lose the entire value of ~~the Fairfax Term Loan to EXCO. In accordance with the charter of the audit committee of~~their investment in our Board of Directors, our audit committee reviewed and pre-approved the terms of the Fairfax Term Loan as a related party transaction, and our Board of Directors determined that the terms of the Fairfax Term Loan were no less favorable to EXCO or our subsidiaries than those that could be obtained in arm’s length dealings with non-affiliates, and, in the good faith judgment of our Board of Directors, no comparable transaction was available with which to compare the Fairfax Term Loan and the Fairfax Term Loan was fair, from a financial point of view, to EXCO.business.

Despite the approval of the terms of the Fairfax Term Loan, there can be no assurance that any actual or potential conflicts of interest between Mr. Mitchell’s duties to EXCO and Mr. Mitchell’s duties to Hamblin Watsa will be resolved in a manner that does not adversely affect our business, financial condition or results of operations. In addition, any actual or perceived conflict of interest may have a negative impact the value of our common shares.


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

Issuer repurchases of common shares

The following table details our repurchase of common shares for the three months ended September 30, ~~2015:~~2016:

Period Total Number of Shares Purchased (1) 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) (2)
July 1, 2015 - July 31, 2015 16,621
$ 1.03
—
$ 192.5
August 1, 2015 - August 31, 2015 —
—
—
192.5
September 1, 2015 - September 30, 2015 —
—
—
192.5
Total 16,621
$ 1.03
—



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)	~~Represents shares that were tendered by employees to satisfy minimum tax withholding amounts for the vesting of restricted share awards.~~


~~(2)~~	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.

~~Table of Contents~~

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:	~~October 28, 2015~~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 ~~Financial~~Accounting Officer and Corporate Controller
		~~and Chief~~(Principal Accounting ~~Officer~~
		Officer)

~~Table of Contents~~

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 ~~September 8,~~November 16, 2015 and filed on ~~September 9,~~November 17, 2015 and incorporated by reference herein.


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


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


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


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


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


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


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


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, ~~(File No. 333-192898),~~ filed on December 17, 2013 and incorporated by reference herein.

~~Table of Contents~~


~~4.7~~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.


~~4.8~~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.


~~4.9~~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.

~~4.10~~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.

~~4.11~~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.*

~~Table of Contents~~


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.*


~~10.10~~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.*


~~10.11~~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.*


~~10.12~~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.*


~~10.13~~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.


~~10.14~~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.*


~~10.15~~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.*


~~10.16~~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.*


~~10.17~~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.*


~~10.18~~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.


~~10.19~~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.


~~10.20~~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.


~~10.21~~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.


~~10.22~~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.


~~10.23~~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.

~~Table of Contents~~

~~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.~~


~~10.24~~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.


~~10.25~~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.


~~10.26~~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.

~~10.27~~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.


~~10.28~~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.


~~10.29~~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.


~~10.30~~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.


~~10.31~~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, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.~~

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.


~~10.32~~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.


~~10.33~~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.*


~~10.34~~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.

~~10.35~~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.

~~Table of Contents~~

~~10.36~~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.

~~10.37~~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.

~~10.38~~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.


~~10.39~~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.

~~10.40~~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.


~~10.41~~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.


~~10.42~~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.


10.47	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.


~~10.43~~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.


~~10.44~~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.

~~10.45~~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.


~~10.46~~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.


~~10.47~~10.52	Form of Purchase Agreement, filed as an Exhibit to EXCO’s Form 8-K, dated as of October 30, 2015 and filed on November 2, 2015 and incorporated by reference herein.


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


~~10.48~~10.54	Amended and Restated Participation Agreement, dated July ~~31, 2013,~~25, 2016, by and among Admiral A Holding L.P., TE Admiral BA Holding L.P., Colt Admiral A Holding L.P. and EXCO Operating Company, ~~LP, 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.~~

~~Table of Contents~~


~~10.49~~	~~Amendment No. 1 to Participation Agreement, dated April 17, 2014, among EXCO Operating Company, LP, Admiral A Holding L.P. and Admiral B Holding L.P.~~LP., filed as an Exhibit to ~~EXCO's Quarterly~~EXCO’s Current Report on Form ~~10-Q for the Quarter Ended June 30, 2014~~8-K, dated July 25, 2016 and filed on July ~~30, 2014~~27, 2016 and incorporated by reference herein.


~~10.50~~	Amendment No. 2 to Participation Agreement, dated June 1, 2015, among EXCO Operating Company, LP, Admiral A Holding L.P., TE Admiral A Holding L.P. and Colt A Holding L.P., 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.


~~10.51~~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.


~~10.52~~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.

~~10.53~~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.


~~10.54~~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.*


~~10.55~~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.*


~~10.56~~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.*


~~10.57~~10.61	EXCO Resources, Inc. 2016 Management Incentive Plan, dated April 20, 2016, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 20, 2016 and filed on April 26, 2016 and incorporated by reference herein.*


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


~~10.58~~	Amended and Restated Retention Agreement, dated May 14, 2015, by and between William L. Boeing 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.*


~~10.59~~	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.*


~~10.60~~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.*


~~10.61~~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.


~~10.62~~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.

~~Table of Contents~~


~~10.63~~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.


~~10.64~~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.~~


~~10.65~~	~~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.~~


~~10.66~~	~~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.~~


~~10.67~~	~~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.


10.68	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.


~~10.70~~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.


~~10.71~~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.


~~10.72~~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.

~~10.73~~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.

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.

~~10.74~~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.

~~10.75~~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.

~~Table of Contents~~


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



(in thousands, except prices)	Volume Mmbtu/Bbl	Weighted average strike price per Mmbtu/Bbl		Fair value at September 30, 2015
Natural gas:
Swaps:
Remainder of 2015	12,650	$	4.02	$	17,901
2016	23,790	3.23		10,133
2017	10,950	3.28		3,150
2018	3,650	3.15		345
Call options:
Remainder of 2015	5,060	4.29		(3		)
Three-way collars:
Remainder of 2015	6,900			3,364
Sold call		4.47
Purchased put		3.83
Sold put		3.33
2016	10,980			4,659
Sold call		4.80
Purchased put		3.90
Sold put		3.40
Total natural gas				$	39,549
Oil:
Swaps:
Remainder of 2015	322	$	86.44	$	12,873
2016	915	61.89		11,473
Basis swaps:
Remainder of 2015	23	6.10		79
Call options:
Remainder of 2015	92	100.00		—
Total oil				$	24,425
Total oil and natural gas derivative financial instruments				$	63,974



Number of shares issuable	Exercise Price	Term
15,000,000	$2.75	April 30, 2019
20,000,000	$4.00	March 31, 2020
20,000,000	$7.00	March 31, 2021
25,000,000	$10.00	March 31, 2021



(in thousands, except prices)	NYMEX gas volume - Mmbtu	Weighted average contract price per Mmbtu		NYMEX oil volume - Bbls	Weighted average contract price per Bbl
Swaps:
Remainder of 2015	12,650	$	4.02	322	$	86.44
2016	23,790	3.23		915	61.89
2017	10,950	3.28		—	—
2018	3,650	3.15		—	—
Basis swaps:
Remainder of 2015	—	—		23	6.10
Call options:
Remainder of 2015	5,060	4.29		92	100.00
Three-way collars:
Remainder of 2015	6,900			—
Sold call		4.47			—
Purchased put		3.83			—
Sold put		3.33			—
2016	10,980			—
Sold call		4.80			—
Purchased put		3.90			—
Sold put		3.40			—



Period	Total Number of Shares Purchased (1)	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) (2)
July 1, 2015 - July 31, 2015	16,621	$	1.03	—	$	192.5
August 1, 2015 - August 31, 2015	—	—		—	192.5
September 1, 2015 - September 30, 2015	—	—		—	192.5
Total	16,621	$	1.03	—

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Accelerated filer

Non-accelerated filer

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Smaller reporting company